*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review ***

6560-50 **EO 12866_CPP 2060 AR33 Final_20150529**

**ENVIRONMENTAL PROTECTION AGENCY**

**40 CFR Part 60 [EPA-HQ-OAR-2013-0602; FRL-XXXX-XX-OAR]** 

**RIN 2060-AR33**  **Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units** 

**AGENCY:** Environmental Protection Agency (EPA).

**ACTION:** Final rule.

**SUMMARY:** In this action, the Environmental Protection Agency (EPA) is establishing final emission guidelines for states, U.S. territories, and tribes to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired electric generating units (EGUs). Specifically, the EPA is establishing: 1) carbon dioxide (CO 2 ) emission performance rates for two source categories of existing fossil fuel-fired EGUs, fossil fuel-fired electric utility steam generating units and stationary combustion turbines, and 2) guidelines for the development, submittal and implementation of state plans that implement the CO 2 emission performance rates. This final rule will continue progress already underway in the U.S. to reduce CO 2 emissions from the utility power sector.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 2 of 1275

**DATES:** The final rule is effective on **[INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]** 

. **ADDRESSES:** Docket

. The EPA has established a docket for this action under Docket No. EPA–HQ–OAR–2013-0602. All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some information is not publicly available (e.g., confidential business information (CBI) or other information for which disclosure is restricted by statute). Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in http://www.regulations.gov or in hard copy at the EPA Docket Center, EPA WJC West Building, Room 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. For additional information about the EPA’s public docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.

World Wide Web. In addition to being available in the docket, an electronic copy of this final rule will be available on the World Wide Web (WWW). Following signature, a copy of this*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 3 of 1275 final rule will be posted at the following address: http://www.epa.gov/cleanpowerplan/. A number of documents relevant to this rulemaking, including technical support documents, a legal memorandum, and the regulatory impact analysis, are also available at http://www.epa.gov/cleanpowerplan/. These and other related documents are also available for inspection and copying in the EPA docket for this rulemaking.

**FOR FURTHER INFORMATION CONTACT:** 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: vasu.amy@epa.gov or Mr. Colin Boswell, Measurements Policy Group (D243-05), Sector Policies and Programs Division, U.S. EPA, Research Triangle Park, NC 27711; telephone number (919) 541-2034, facsimile number (919) 541-4991; email address: boswell.colin@epa.gov.

**SUPPLEMENTARY INFORMATION:** Acronyms. A number of acronyms and chemical symbols are used in this preamble. While this may not be an exhaustive list, to ease the reading of this preamble and for reference purposes, the following terms and acronyms are defined as follows: ACEEE American Council for an Energy Efficient Economy AEO Annual Energy Outlook AFL-CIO American Federation of Labor and Congress of Industrial Organizations*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 4 of 1275 ASTM American Society for Testing of Materials BSER Best System of Emission Reduction Btu/kWh British Thermal Units per Kilowatt-hour CAA Clean Air Act CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CEMS Continuous Emissions Monitoring System CHP Combined Heat and Power CO 2 Carbon Dioxide DOE U.S. Department of Energy ECMPS Emissions Collection and Monitoring Plan System EERS Energy Efficiency Resource Standard EGU Electric Generating Unit EIA Energy Information Administration EM&V Evaluation, Measurement and Verification EO Executive Order EPA Environmental Protection Agency FERC Federal Energy Regulatory Commission FR Federal Register GHG Greenhouse Gas GW Gigawatt HAP Hazardous Air Pollutant HRSG Heat Recovery Steam Generator IGCC Integrated Gasification Combined Cycle IPCC Intergovernmental Panel on Climate Change IPM Integrated Planning Model IRP Integrated Resource Plan ISO Independent System Operator kW Kilowatt kWh Kilowatt-hour lb CO 2 /MWh Pounds of CO 2 per Megawatt-hour LBNL Lawrence Berkeley National Laboratory MMBtu Million British Thermal Units MW Megawatt MWh Megawatt-hour NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System Commissioners NAS National Academy of Sciences NGCC Natural Gas Combined Cycle NOx Nitrogen Oxides NRC National Research Council NSPS New Source Performance Standard NSR New Source Review NTTAA National Technology Transfer and Advancement Act OMB Office of Management and Budget*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 5 of 1275

PM Particulate Matter PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSB Public Service Board PUC Public Utilities Commission REC Renewable Energy Credit RES Renewable Energy Standard RFA Regulatory Flexibility Act RGGI Regional Greenhouse Gas Initiative RIA Regulatory Impact Analysis RPS Renewable Portfolio Standard RTO Regional Transmission Operator SBA Small Business Administration SBC System Benefits Charge SCC Social Cost of Carbon SIP State Implementation Plan SO 2 Sulfur Dioxide Tg Teragram (one trillion (10 12 ) grams) TSD Technical Support Document TTN Technology Transfer Network UMRA Unfunded Mandates Reform Act of 1995 UNFCCC United Nations Framework Convention on Climate Change USGCRP U.S. Global Change Research Program VCS Voluntary Consensus Standard Organization of This Document. The information presented in this preamble is organized as follows:

**I. General Information**  A. Executive Summary B. Organization and Approach for this Final Rule **II. Background** A. Climate Change Impacts from GHG Emissions B. GHG Emissions from Fossil Fuel-Fired EGUs C. The Utility Power Sector D. Congress’ Awareness of Climatic Change E. International Agreements and Actions F. Statutory and Regulatory Requirements G. Legislative and Regulatory Background for CAA Section 111 H. Clean Power Plan Proposal and Supplemental Proposal I. Stakeholder Outreach and Consultations J. Comments on the Proposal **III. Rule Requirements and Legal Basis** A. Summary of Rule Requirements*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 6 of 1275 B. Summary of Legal Basis **IV. Authority for this Rulemaking, Definition of Affected Sources, and Treatment of Categories**  A. EPA’s Authority under CAA Section 111(d) B. CAA Section 112 Exclusion to CAA Section 111(d) Authority C. Authority to Regulate EGUs D. Definition of Affected Sources E. Combined Categories and Codification in the Code of Federal Regulations **V. The Best System of Emission Reduction and Associated Building Blocks**  A. The Best System of Emission Reduction (BSER) B. Legal Discussion of Certain Aspects of the BSER C. Building Block 1—Efficiency Improvements at Affected Coal- Fired Steam EGUs D. Building Block 2—Generation Shifts Among Affected EGUs E. Building Block 3—Renewable Generating Capacity **VI. Source Category-Specific CO 2**  **Emission Performance Rates** A. Overview B. Performance Rate Requirements C. Form of the Performance Rates **VII. Statewide CO 2**  **Goals** A. Overview B. Translating Source Category-Specific Emission Performance Rates to Statewide CO 2 Emission Performance Goals **VIII. State Plans** A. Overview B. State Plan Performance Periods C. State Plan Approaches D. State Plan Components and Approvability Criteria E. State Plan Submittal and Approval Process and Timing F. State Plan Performance Demonstrations G. Considerations for Incorporating CO 2 Emission Reduction Measures in State Plans H. Additional Considerations for State Plans I. Resources for States to Consider in Developing Plans **IX. Community Considerations** A. Proximity Analysis B. Title VI C. Community Engagement in State Plan Development D. Co-pollutants E. EPA Continued Engagement F. Key Changes from Proposal **X. Interactions with Other EPA Programs and Rules** A. Implications for the NSR Program B. Implications for the Title V Program*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 7 of 1275

C. Interactions with Other EPA Rules **XI. Impacts of this Action** A. What are the air impacts? B. Endangered Species Act C. What are the energy impacts? D. What are the compliance costs? E. What are the economic and employment impacts? F. What are the benefits of the proposed action? **XII. Statutory and Executive Order Reviews** A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act of 1995 E. Executive Order 13132, Federalism F. Executive Order 13175, Consultation and Coordination with Indian Tribal Governments G. Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks H. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations **XIII. Statutory Authority**

**I. General Information**

A. Executive Summary 1. Introduction and Purpose of the Regulatory Action Under the authority of Clean Air Act (CAA) section 111(d), the EPA is establishing CO 2 emission guidelines for existing fossil fuel-fired electric generating units (EGUs) – the Clean Power Plan. As in the proposal, these final guidelines, when fully implemented, will achieve significant reductions in CO 2 emissions by 2030. At the same*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 8 of 1275 time, the guidelines offer states and utilities substantial flexibility and latitude in achieving these reductions. In this final rule, the EPA has established a CO 2 emission performance rate for each of two subcategories of fossil

fuel-fired EGUs -- fossil fuel-fired electric steam generating units and stationary combustion turbines. The performance rates reflect the “best system of emission reductions ... adequately demonstrated” (BSER) for CO 2 emissions from the EGU source category. The guidelines also provide for the development, submittal and implementation of state plans that implement the CO 2 emission performance rates, either directly by means of source-specific requirements or through measures that achieve equivalent CO 2 reductions from the same group of EGUs. 1 States, U.S. territories, and tribes 2 with one or more affected EGUs will

1 A state plan must be developed by a state, the District of Columbia, a U.S. territory, 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 if it has one or more affected EGUs in its jurisdiction. 2 In the case of a tribe that has one or more affected EGUs in its area of Indian country, the tribe has the opportunity, but not the obligation, to establish a CO 2 emission performance standard and a CAA section 111(d) plan for its area of Indian country. If the EPA determines that such a plan is necessary or appropriate, it has the responsibility to establish CAA section 111(d) plans for areas of Indian country where affected sources are located unless a tribe on whose lands an affected source (or sources) is located seeks and obtains authority from the EPA to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 9 of 1275 be required to develop and implement plans to ensure that their affected EGUs, individually, in aggregate, or in combination with other measures undertaken by the state, 3 achieve the equivalent of the final CO 2 emission performance rates by 2030. State plans must also ensure that emission reductions from the affected EGUs begin no later than 2022 and that, during the period from 2022 to 2029, affected EGUs in the state collectively meet the equivalent of the

interim CO 2 emission performance rates. The EPA has translated the source category-specific CO 2 emission performance rates into equivalent state-level

rate-based and mass-based CO 2 goals in order to maximize the range of choices, including application of statewide policy measures as well as, or instead of, source-specific requirements, that states will have in developing their plans. In this summary, we discuss the purpose of the rule, key changes from the proposal, the context for the rulemaking, the

develop and implement a CAA section 111(d) plan, pursuant to the 40 CFR 49.9 3 The CAA section 111(d) emission guidelines apply to the 50 states, 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 eligible to develop and implement a CAA section 111(d) plan. In this preamble, in instances where these governments are not specifically listed, the term “state” is used to represent them.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 10 of 1275 major provisions of the final rule, the estimated CO 2 emission reductions, and the costs and benefits expected to result from full implementation of this final action. Greater detail is provided in the body of this preamble, the regulatory impacts analysis (RIA), the response to comments documents, and various technical support documents and memoranda addressing specific topics. The purpose of this CAA section 111(d) rule is to address

CO 2 emissions from fossil fuel-fired power plants in the U.S. because they are the largest domestic stationary source of emissions of carbon dioxide (CO 2 ), the most prevalent of the group of air pollutant greenhouse gases (GHG) that the EPA has determined endangers public health and welfare through its contribution to climate change. This rule establishes for the first time emission guidelines for existing power plants that will lead to significant reductions in CO 2 emissions. At the same time, these emission guidelines will result in cleaner generation from the existing power plant fleet and will support continued investments by the industry in cleaner power generation to ensure reliable, affordable electricity now and into the future. As with past EPA rules addressing air pollution from the utility power sector, these guidelines have been designed with a clear recognition of the unique features of this*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 11 of 1275 sector. Like past rules under CAA section 111, this rule relies on proven technologies and approaches to set achievable

standards that will lead to cost-effective CO 2 reductions at power plants across the country. In fact, the emission guidelines reflect strategies, technologies and approaches already in widespread use by utilities and states. CAA section 111(d) itself relies on a state-EPA partnership to accomplish the required emission reductions. This rulemaking, which will be implemented through that partnership, is a significant step that will reduce air pollution, in this case GHG emissions, in the

U.S. This final rule is also a significant step forward in implementing the President’s Climate Action Plan. 4 To address the far-reaching harmful consequences and real economic costs of climate change, the President’s Climate Action Plan details a broad array of actions to reduce GHG emissions that contribute to climate change and its harmful impacts on public health and the environment. Climate change is already occurring in this country, affecting the health, economic well-being and quality of life of Americans across the country, and especially those in the most vulnerable communities. This CAA section 111(d)

4 The President’s Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27s climateactionplan.pdf*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 12 of 1275 rulemaking to reduce GHG emissions from existing power plants, and the concurrent CAA section 111(b) rulemaking to reduce GHG emissions from new, modified, and reconstructed power plants, implement one of the strategies of the Climate Action Plan. Nationwide, by 2030, this final rule will achieve CO 2 emission reductions from the utility power sector of approximately [X] percent from CO 2 emission levels in 2005. The EPA projects that these reductions along with reductions in other air pollutants, to which this rule will lead, will result in net climate and health benefits of $[X] billion to $[X] billion. 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 [X] percent of the projected generation and natural gas providing about [X] percent of the projected generation. 2. Key changes from proposal The June 2014 proposal featured several important elements: 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 to maximize the range of

choices that states and utilities could select in order to achieve their emission limitations at low cost while ensuring*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 13 of 1275 electric system reliability. The state goals reflected an approach to the BSER that was intended to capture both the unique interconnected nature of the utility power sector and the set of actions, strategies and programs that are already under way at the state and utility level that have been resulting in

CO 2 emission reductions. They also reflected the fact that each state has its own energy profile and state-specific policies and needs relative to the production and use of electricity. The final guidelines continue to embrace this basic approach, but they also incorporate significant changes that respond directly to the comments, requests and concerns of states and other stakeholders, while better serving the critical objectives of the basic approach of the proposal. Together with the proposal, this final rule is the product of one of the most extensive and long-running public engagement processes the EPA has ever conducted, starting in the summer of 2013 and continuing through December 2014, and resulting in millions of comments from stakeholders, which we have carefully considered over the past several months. T he EPA gained crucial insights from the more than 4 million comments that the agency received on the proposal and on notices leading to this final rulemaking, from stakeholders that include state environmental and energy officials, tribal officials, public utility*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 14 of 1275 commissioners, system operators, utility and other industry representatives, labor leaders, public interest advocates, community leaders, and members of the public. As a result, these final emission guidelines reflect changes from the proposal that are directly responsive to the comments we received from the many and diverse stakeholders. These final guidelines bear the stamp of the information and input the EPA gleaned from its extensive outreach process and from the comment record. The guidelines reflect thinking and information that states and utilities provided to us about both the best approach to establishing CO 2 emission reduction requirements for EGUs and the most effective ways to create true flexibility for states and utilities in meeting these requirements. These final rules also reflect the results of EPA’s robust and ongoing consultation with federal, state and regional energy agencies and authorities, to ensure that the actions sources will take to reduce GHG emissions will not compromise electric system reliability or affordability of the U.S. electricity supply.At proposal, the EPA made it clear that our intent was twofold – first, to establish CO 2 emission reduction requirements that relied both on the distinctive nature of the electricity system in which affected EGUs operate and on the actions, strategies and policies states and utilities have already been*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 15 of 1275 undertaking, and, second, to provide states and utilities with broad flexibility and choice in meeting those requirements in order to minimize costs to ratepayers and to ensure the reliability of electricity supply. Thus, in our thorough

examination of the comment record and of information received during the engagement process, we paid particular attention to information and suggestions that addressed ways to ensure that this final rule succeeds in fulfilling the dual objectives of the proposal. The resulting changes in these final guidelines are highlighted by: 1) a new start date of 2022 for the interim period, 2) a gradual application of the BSER over the 2022-2029 interim period, such that a state has substantial latitude in selecting its own emission reduction “glide path” over that period, 3) the BSER being derived from generation options only and not from demand-side energy efficiencies, 4) the BSER reflecting the realities of electricity operations over the three regional Interconnections, as well as up-to-date information about the cost and availability of clean generation options, including reflecting the fact that new NGCC is also a clean generation option, 5) a combination of provisions expressly designed to address electric system reliability, 6) source-specific CO 2 emission performance rates that are uniform*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 16 of 1275 across the two fossil fuel-fired source categories covered in these guidelines, 7) additional, more flexible options for states and utilities to adopt multi-state compliance strategies, 8) an extension of up to two years for all states to submit their final compliance plans following submittal of an initial plan in 2016 and 9) a variation on the proposal’s “portfolio” option for state plans – called the “state measures” approach - that offers the same options for states but with a firmer legal

foundation. This suite of changes is the product of compelling information and analysis provided to the EPA via the comment record – and by the work of, and consultation with, other federal agencies, notably the Federal Energy Regulatory Commission (FERC) and the U.S. Department of Energy (DOE). 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 17 of 1275 time for states, utilities, and grid operators to implement strategies to achieve CO 2 reductions. They expressed concern that, in the proposal, at least some states were required to reduce emissions in 2020 to levels that would require abrupt shifts in generation in ways that raised concerns about impacts to electric system reliability, ratepayer bills, and stranded assets. To many commenters, the proposal’s 2020 start date for achieving CO 2 reductions, together with the stringency of the

interim CO 2 goal, bore significant reliability implications, in particular. In this final rule, the agency is addressing these concerns, in part, by adjusting the compliance timeframe from a 10-year interim period that begins in 2020 to an 8-year interim period that begins in 2022, and by refining the approach for meeting interim CO 2 emission performance rates (a glide path separated into three steps, 2022-2024, 2025-2027, and 2028-2029, and also achievable “on average” over the 8-year interim period). In response to the concerns of commenters that the proposal’s 10-year interim target failed to afford sufficient flexibility, the final guidelines’ approach will provide states with realistic options for customizing their emission reduction trajectories. Of equal importance, the approach provides more time for planning, consultation and decision making in the formulation of state plans and in EGUs’ choices of compliance*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 18 of 1275 strategies. Both FERC’s May 15, 2015 letter and the comment record, as well as other information sources, made it clear that providing sufficient time for planning and implementation was essential to ensuring electric system reliability. The final guidelines’ “step-down” 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 reliability assurance, 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. Commenters urged the EPA to confine its BSER determination to actions that involve generation. In response, the final guidelines’ BSER determination does not take into account demand-side energy efficiency (EE), and the emission performance rates for each of the two source categories do not reflect 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 energy efficiency measures*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 19 of 1275 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 meeting emission reduction requirements. Since commenters pointed out that the utility power sector operates over regional interconnections that are not constrained by state borders, the BSER determination and the resulting source category-specific emission performance rates take into account that reality. The final guidelines’ BSER

determination takes into account recent reductions in the cost of clean energy technology, as well as projections of continuing

cost reductions. With a revised start date for emission reductions of 2022, instead of 2020, as proposed, the guidelines reflect that the additional time aligns with the adoption of lower-cost clean technology and thus its incorporation in the BSER at higher levels. At the same time, the 2022-2029 interim period will more easily allow for companies to take advantage of improved clean energy technologies as potential least cost options.

The EPA’s decision to exclude demand-side EE from its BSER determination responds to numerous stakeholders’ request that the agency not base the final emission guidelines on requiring*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 20 of 1275 that utilities produce less generation. After consideration of these comments and extensive comments on a range of topics related to the best system of emission reduction (BSER), the agency has revised its determination of the BSER. In this final action, the agency has determined that the BSER comprises the first three of the four proposed building blocks identified at proposal, with certain refinements to the three building blocks. Commenters pointed out 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 all previous new source performance standards (NSPS). The effect, they observed, was that the proposal’s de facto emission standards for the same sources were not uniform, but varied inappropriately from state to state, depending on what each state’s goal was. Many commenters also pointed out that the EPA must establish the BSER specifically for affected sources, rather than by means of merely setting state-specific goals. In response to these and similar comments, the final guidelines express the BSER by establishing performance-based CO 2 emission rates that are uniform across each of two source categories – fossil fuel-fired electric steam generating units and stationary combustion turbines – for the affected EGUs covered by the guidelines. We cannot emphasize enough that, while the final*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 21 of 1275 guidelines now take a source-specific approach in setting CO 2 emission performance rates, this does not change the fact that each state’s goal is tailored to its particular sources, and it in no way alters or curtails the flexibility inherent in the proposal’s state-specific goals approach, which the final guidelines retain (and, as discussed in Section VIII of this preamble, enhance in various ways). Thus, to maintain the proposal’s flexibility for states, the guidelines continue to define state planning and implementation obligations through state-level goals, which we have calculated by translating the source category-specific CO 2 emission performance rates into equivalent statewide rate-based and mass-based CO 2 goals. For the state plan approaches included at proposal, commenters expressed support for the objectives served by the “portfolio” option but also raised concerns about its legality, with respect, in particular, to the Clean Air Act’s enforceability requirements. Some of these commenters identified a “state commitment approach” with backstop measures as an option for state plans 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 22 of 1275 standards” approach, and a “state measures” approach that requires the inclusion of backstop measures. As in the proposal, in order to comply with these guidelines, states will have to ensure that implementation of the emission standards established for their affected EGUs, either individually, in aggregate, or in combination with other measures undertaken by the state, achieves the equivalent of the source category-specific CO 2 emission performance rates. This revision provides consistency in the treatment of sources while still tailoring required CO 2 reductions to individual states. 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 trackingsystems to support state administration of rate-based and massbased emission trading programs. In this final rule, as we proposed, states may use trading or other multi-unit compliance 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 EUGs. In addition, in response to concerns from states and power*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 23 of 1275 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 2 reductions, without the need for up-front interstate agreements. The EPA is committed to working with states to provide support for tracking of emissions and allowances or credits, to help implement multi-state trading or other multi-unit compliance approaches. Stakeholders, particularly states, provided compelling information that it will 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 fully recognize commenters’ concerns. To strike the proper balance, the EPA has developed a revised state plan submittal schedule. The EPA is requiring states to submit an initial plan 13 months after signature (by August 31, 2016), to assure that states begin to address the urgent needs for reductions quickly, and is providing until August 31, 2018, for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 24 of 1275 states to submit a final plan, if 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. A number of commenters stressed the importance of final guidelines that addressed the need to ensure that the program would not 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. Many aspects of the final rule’s design are intended to support electric system reliability. In addition to not requiring reductions before 2022 and to allowing significant flexibility in how the CO 2 emission performance rates or the statewide CO 2 goals are met, we are requiring that states demonstrate that they have considered reliability in developing their state plans and have consulted with state utility agencies and/or regional planning authorities. These final guidelines further provide states with the option of proposing amendments to approved plans in the event that reliability challenges arise that need to be remedied by amending the state plan. The final rule also includes a reliability safety valve to address situations where, because of an unanticipated catastrophic event, there is a conflict between*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 25 of 1275 the requirements imposed on an affected unit and the maintenance of reliability. The final rule also retains flexibilities presented in the proposal and offers additional opportunities, including opportunities for trading within and between states, and other multi-state compliance approaches that will further support electric system reliability. Stakeholders requested that the program not impose undue burdens on low-income ratepayers. We share this concern, and thefinal rule ensures that bill-lowering measures such as demandside EE continue to be a major compliance option. In addition, to ensure opportunities for communities, particularly citizens who could be impacted by decisions, to continue to participate in decision making, we are taking steps to ensure that states are actively engaging with communities as part of their public participation process in the formulation of state plans. We note that, given the substantial reductions in a range of air pollutants, in addition to GHGs, that will occur along with the GHG reductions, this rule will result in significant near-term public health benefits in communities in addition to the longer term benefits resulting from the reductions in GHGs. In their comments, many states identified the need for the EPA to maintain regular contact/forums with states throughout the implementation process and to provide guidance, including*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 26 of 1275 guidance on RE and EE emission measurement and verification (EM&V). To provide state and local governments and other stakeholders, including communities, 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, tribes and territories to raise technical and policy questions. The agency

will host or co-host a number of webinars about various components of the final rule currently planned for 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, tribes, and territories that are implementing the final rule, and also to inform the training for citizens, including members of communities that could be impacted, to support their participation in the state plan development process. 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 the U.S. Department of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 27 of 1275 Energy and other federal agencies, will continue to make these

resources available via a dedicated website. 3. Context for this rulemaking a. Climate change impacts. This final rule is an important step toward achieving the GHG emission reductions needed to address the serious threat of climate change. GHG pollution threatens the American public by leading to damaging and long-lasting changes in our climate that can have a range of severe negative

effects on human health and the environment. CO 2 is the primary GHG pollutant, accounting for nearly three-quarters of global

GHG emissions 5 and 31 percent of U.S. GHG emissions. 6 The May 2014 report of the National Climate Assessment 7 concluded that climate change impacts are already manifesting themselves and imposing losses and costs. The report documents increases in extreme weather and climate events in recent decades, with resulting damage and disruption to human well-being, infrastructure, ecosystems, and agriculture, and projects

5 Intergovernmental Panel on Climate Change (IPCC) report, “Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change,” 2007. Available at http://epa.gov/climatechange/ghgemissions/global.html 6 From Tables ES-4 and 3-5 of “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15, 2015. 7 U.S. Global Change Research Program, Climate Change Impacts in the United States: The Third National Climate Assessment, May 2014. Available at http://nca2014.globalchange.gov/.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 28 of 1275 continued increases in impacts across a wide range of communities, sectors, and ecosystems. New scientific assessments since 2009, when the EPA determined that GHGs pose a threat to human health and the environment (the “Endangerment Finding”), highlight the urgency of addressing the rising concentration of

CO 2 in the atmosphere. Certain groups, including children, the elderly, and the poor, are most vulnerable to climate-related effects. 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 — including heat waves, degraded air quality,

and extreme weather events – which are associated with increased deaths, illnesses, and economic challenges. Studies also find that climate change poses particular threats to the health, wellbeing, and ways of life of indigenous peoples in the United

States. b. The utility power sector. One of the strategies of the

President’s Climate Action Plan is to reduce CO 2 emissions from power plants. This is because fossil fuel-fired EGUs are by far the largest emitters of GHGs, primarily in the form of CO 2 , among stationary sources in the U.S. and, among fossil fuel-fired EGUs, coal-fired units are by far the largest emitters. To accomplish this goal, President Obama issued a Presidential*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 29 of 1275

Memorandum 8 that recognized the importance of significant and prompt action. The Memorandum directed the EPA to complete carbon pollution standards, regulations or guidelines, as appropriate, for new, modified, reconstructed and existing power plants, and in doing so to build on state leadership in moving toward a cleaner power sector. In this action and the concurrent CAA section 111(b) rule, the EPA is finalizing regulations to

reduce GHG emissions from fossil fuel-fired EGUs. This CAA section 111(d) action builds on actions states and utilities are already taking to move toward cleaner generation of electric

power. Unlike all other industrial sectors, where sources effectively operate independently and on a local-site scale, the utility power sector comprises a unique system of electricity resources that operate in a complex and interconnected grid where electricity generally flows freely (e.g., portions of the system cannot be easily isolated through the use of switches or valves as can be done in a other networked systems like trains and pipeline systems). That grid is physically interconnected and operated on an integrated basis across large regions. In

8 Presidential Memorandum – Power Sector Carbon PollutionStandards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 30 of 1275 this interconnected system, electricity supply and demand are reliably balanced using available generation and demand-side resources, including energy efficiency, demand response and a wide range of low- and zero-emitting sources which are all managed to meet the system needs in a reliable and efficient

manner. The electricity system is largely integrated, with numerous entities that have both the capability and the responsibility to maintain a reliable electric system. The Federal Energy Regulatory Commission (FERC), the U.S. Department of Energy (DOE), state public utility commissions, independent system operators (ISOs), regional transmission organizations (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. 9 The interconnection is such that

9 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 159 (2d ed. 2010).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 31 of 1275 “[i]f a generator is lost in New York City, its effect is felt in Georgia, Florida, Minneapolis, St. Louis, and New Orleans.” 10 The U.S. Supreme Court has similarly recognized the interconnected nature of the electricity grid. 11 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

10 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 160 (2d ed. 2010). 11 Federal Power Comm’n v. Florida Power & Light Co. , 404 U.S. 453, at 460 (1972) (quoting a Federal Power Commission hearing examiner, "`If a housewife in Atlanta on the Georgia system turns on a light, every generator on Florida’s system almost instantly is caused to produce some quantity of additional electric energy which serves to maintain the balance in the interconnected system between generation and load.’”) (citation omitted). See also New York v. FERC , 535 U.S. 1, at 7-8 (2002) (stating that “any electricity that enters the grid immediately becomes a part of a vast pool of energy that is constantly moving in interstate commerce.”) (citation omitted). In Federal Power Comm’n v. Southern California Edison Co. , 376 U.S. 205 (1964), the Supreme Court found that a sale for resale of electricity from Southern California Edison to the City of Colton, which took place solely in California, was under Federal Power Commission jurisdiction because some of the electricity that Southern California Edison marketed came from out of state. The Supreme Court stated that, “`federal jurisdiction was to follow the flow of electric energy, an engineering and scientific, rather than a legalistic or governmental, test.’” Id. at 210, quoting Connecticut Light & Power Co. v. Federal Power Commission , 324 U.S. 515, 529 (1945) (emphasis omitted).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 32 of 1275 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 that electricity production takes place, at least to some extent, interchangeably between and among multiple generation facilities and different types of generation, as evidenced in the enactment or promulgation of pollution reduction programs, such as Title IV of the CAA, the NOx SIP Call, the Cross-State Air Pollution Rule (CSAPR), and the Regional Greenhouse Gas Initiative (RGGI). As these actions show, both Congress and the EPA have consistently tailored legislation and regulations affecting the utility power sector to its unique characteristics. For example, in Title IV of the Clean Air Act Amendments of 1990, Congress established a pollution reduction program specifically for fossil fuel-fired EGUs and designed the SO 2 portion of that program with express recognition of the sector’s ability to shift generation among various EGUs and to reduce pollution by increasing reliance on renewable energy and demand-side energy efficiency. Similarly,

in the NO X SIP Call, the Clean Air Interstate Rule (CAIR), and CSAPR, the EPA established pollution reduction programs focused on fossil fuel-fired EGUs and designed those programs with*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 33 of 1275 express recognition of the sector’s ability to shift generation among various EGUs. In this action, we continue that approach. Both the source category-specific performance rates, and the pathways offered to achieve them, reflect, and are tailored to, the unique characteristics of the utility power sector. When the EPA evaluated this sector for development of this rulemaking, we found that, across the nation, many states, cities and towns, and owners and operators of EGUs have shown leadership in creating and implementing policies and programs

that reduce CO 2 emissions from the utility power sector while achieving other economic, environmental and energy benefits. Some of these activities, such as market-based programs and GHG performance standards, directly require CO 2 emission reductions

from EGUs. Others reduce CO 2 emissions by increasing the use of

lower and zero CO 2 emission alternatives, including both renewable generation and demand-side energy efficiency. For example, many states have adopted renewable portfolio standards (RPS) and energy efficiency resource standards (EERS). In other cases, utilities have chosen to construct renewable generation and/or implement demand-side energy efficiency programs, at least in part, to reduce CO 2 emissions. These approaches take advantage of cost-effective opportunities for improving the efficiency of fossil fuel-fired EGUs and using lower-emitting*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 34 of 1275 generation across the electricity system’s interconnecting grid

to reduce emissions from fossil fuel-fired EGUs. The way that power is produced, distributed and used in the United States is already changing as a result of advancements in innovative power sector technologies and in the availability and cost of low-carbon fuel, renewable energy and energy efficient demand-side 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 toaddressing aging assets. In 2025, the average age of the coalfired 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 they need to take account of the age of current assets and infrastructure. Owners/operators of affected EGUs are already pursuing the types of measures contemplated in this rule. Out of 417 entities identified as owners or operators of affected EGUs, representing ownership of 84 percent of the total capacity of the affected EGUs, 191 already own RE generating*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 35 of 1275 capacity in addition to fossil fuel fired generating capacity. In fact, these entities already own aggregate amounts of RE generating capacity equal to 21 percent of the aggregate amounts of their affected EGU capacity. In addition, funding for utility energy efficiency programs has been growing rapidly, increasing from $1.6 billion in 2006 to $6.3 billion in 2013. The 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 additional requirements for existing programs where possible. It also allows states to pursue policies to reduce carbon pollution that: 1) continue to rely on a diverse set of energy resources; 2) ensure electric system reliability; 3) provide affordable electricity; 4) recognize investments that states and power companies are already making; and 5) tailor plans to meet their respective energy, environmental and economic needs and goals, and those of their local communities. Thus, the final guidelines will achieve*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 36 of 1275 meaningful CO 2 emission reductions while maintaining the reliability and affordability of electricity in the U.S. c. CAA section 111(d) requirements. Concurrent with this CAA section 111(d) action, the EPA is finalizing “standards of performance” for CO 2 emissions from new, modified, and reconstructed fossil fuel-fired EGUs under CAA section 111(b). When the EPA establishes CAA section 111(b) new source performance standards (NSPS), 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 is not regulated under the CAA section 109 requirements for the NAAQS or regulated under the CAA section 112 requirements for hazardous air pollutants (HAP).

CO 2 qualifies as such an air pollutant. Unlike the CAA section 111(b) requirements that the EPA establishes and which apply directly to new, modified, or reconstructed sources, under CAA section 111(d), states must develop and submit plans to the EPA

in which the state establishes emission standards for the

affected sources. Under CAA section 111(d), 12 states must establish, in their state plans, emission standards that reflect the degree of emission limitation achievable through the application of the

12 See also 40 CFR 60.22(b)(5).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 37 of 1275 “best system of emission reduction” that, taking into account the cost of achieving such reduction and any non-air quality health and environmental impacts and energy requirements, the Administrator determines has been adequately demonstrated (BSER). 13 Consistent with CAA section 111(d), the EPA is establishing CO 2 emission performance rates for two categories of

affected EGUs that reflect the EPA’s calculation of the emission limitation that each of the two categories can achieve through the application of the BSER. This calculation reflects the degree of emission limitation that the state plan must achieve in aggregate in order to implement the BSER that the EPA has determined has been adequately demonstrated and that, in turn, will be required to be, and via the calculation, has been,applied for the two source categories of affected fossil fuelfired EGUs – fossil fuel-fired electric utility steam-generating units and stationary combustion turbines.

13 Under CAA section 111(a)(1) and (d), the EPA is authorized to determine the BSER and to calculate the amount of emission reduction achievable through applying the BSER. The state is authorized to identify the standard or standards of performance that reflects that amount of emission reduction. In addition, the state is required to include in its state plan the standards of performance and measures to implement and enforce those standards. The state must submit the plan to the EPA, and the EPA must approve the plan if the standards of performance and implementing and enforcing measures are satisfactory. This is discussed in more detail in Sections IV, VI, VII and VIII of this preamble, as well as in the Legal Memorandum.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 38 of 1275 To determine the BSER for reducing CO 2 emissions at affected EGUs, the EPA considered numerous measures that are already being implemented and can be implemented more broadly to improve emission rates and to reduce overall CO 2 emissions from fossil fuel-fired EGUs. Overall, the BSER is based on a range of measures that fall into three main categories, which comprise improving operations at EGUs, shifting generation to lower-emitting affected EGUs, and shifting generation to renewable energy generation. These measures have been amply demonstrated via their current widespread use by utilities and states. Consistent with CAA section 111(d), in this final rule, the EPA is establishing emission guidelines for states to follow in formulating their plans to establish and implement standards of performance to achieve CO 2 emission reductions from fossil

fuel-fired EGUs that are consistent with the BSER. The final guidelines are structured so that states are not required to use each and every one of the measures that the EPA determines constitute the BSER or to apply any one

of those measures to the same extent that the EPA

determines is achievable at reasonable cost on a national basis. Instead, in developing its plan, each state will have the flexibility to select the measure or combination*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 39 of 1275 of measures it prefers in order to achieve the CO 2 emission performance rates for its affected EGUs or meet the equivalent statewide rate- or mass-based CO 2 goal. Thus, a

state could choose to achieve more reductions from one measure encompassed by the BSER and less from another, or

it could choose to include measures such as demand-side EE programs that are not part of the EPA’s BSER determination, as detailed in Section VIII of this preamble. Expressing the states’ obligation in terms of a state-level goal that can be met in aggregate, including through the adoption of

CO 2 emission reduction measures that are not identical to the components of the BSER or are not included in the BSER, rather than exclusively through source-specific emission performance rates, is entirely permissible precisely because the approach mirrors the foundation of the BSER approach itself, namely the interconnected nature of the electricity system in which affected EGUs operate. We expect that affected EGUs in each state will be

able to meet the CO 2 emission performance rates because the emission performance rates represent the application of the BSER specific to the two categories of affected EGUs. 4. Summary of the major provisions a. Overview. Though there are notable revisions – many of which*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 40 of 1275 have been identified above – from the emission guidelines we proposed in June 2014, the proposed guidelines serve as the foundation of this final rule. First, these final guidelines build on the progress already underway to reduce the carbon intensity of power generation in the United States (U.S.). Second, these guidelines reflect the unique interconnected system within which EGUs operate. Thus, the BSER, as determined in these guidelines, incorporates a range of CO 2 -reducing actions. 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 continues to provide states and utilities with time for planning and investment, which is instrumental to ensuring both manageable costs and system reliability and to facilitating clean energy innovation. The final rule continues to express the

CO 2 emission reduction requirements in terms of a state-level goal that reflects the particular mix of power generation in each state, and it continues to provide until 2030, fifteen years from the date of this final rule, for states and sources

to achieve the CO 2 reductions, which numerous commenters, including most sources, states and energy agencies, indicated

was a reasonable timeframe.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 41 of 1275 b. Opportunities for states. Because, as stated above, the final guidelines are designed to build on and reinforce progress by states, cities and towns, and companies on a growing variety of sustainable strategies to reduce power sector CO 2 emissions, states will be able to rely in their CAA section 111(d) plans on, and extend, programs they may already have created to address the power sector. Those states committed to Integrated Resource Planning (IRP) will be able to establish their CO 2 reduction plans within that framework, while states with a more deregulated power sector system will be able to develop CO 2 reduction plans within that specific framework. Each state will have the opportunity to take advantage of a wide variety of strategies for reducing CO 2 emissions from affected EGUs. The EPA and other federal entities, including the U.S. Department of Energy (DOE), the Federal Energy Regulatory Commission (FERC) and the U.S. Department of Agriculture, among others, are committed to sharing expertise with interested states as they develop and implement their plans.

States will be able to address the economic interests of their utilities and ratepayers by using the flexibilities in this final action to: 1) reduce costs to consumers, minimize stranded assets, and spur private investments in renewable energy and energy efficiency technologies and businesses; and 2)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 42 of 1275 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 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. c. Main elements. This final rule has two main elements: 1)

tailored state-level CO 2 goals that are translated from the numerical source category-specific CO 2 emission performance rates resulting from application of the BSER to the source categories of affected EGUs, and 2) guidelines for the development, submittal and implementation of state plans that implement those standards either directly or through measures that achieve the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 43 of 1275 equivalent in aggregate of those rates. 14 In this final action, the EPA is setting performance rates for two categories 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 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 EGUs 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 these final guidelines do identify the

methods which a state can or must use to demonstrate that

the combination of measures and standards that the state does adopt meet its state-level CO 2 goals. 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 meeting them by creating plans that are consistent with the EPA emission guidelines. The EPA

14 A state plan must be developed by a state, the District of Columbia, a U.S. territory, 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 if it has one or more affected EGUs in its jurisdiction.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 44 of 1275 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 (e.g., utility regulatory structure and generation mix) also differ. Therefore, as in the proposal, each state will have the latitude to design a program to meet source-category specific emission performance rates or the equivalent statewide rate- or mass-based goal in a manner that reflects its particular circumstances and energy and environmental policy objectives. Each state can do so on its own, or a state can collaborate with other states and/or tribal governments on multi-state plans – or states can include in their plans the trading tools that EGUs can use to realize additional opportunities for cost savings while continuing to operate across the interstate system through which electricity is produced. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 45 of 1275 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 2 reductions that will ensure that progress is being made in achieving CO 2 emission reductions. States will be able to choose from a wide range of emission reduction measures, including measures that are not part of the BSER, as discussed in detail in Section VIII.G of this preamble. d. Determination of the BSER. In issuing this final rulemaking, the EPA is implementing statutory provisions that have been in place since Congress first enacted the CAA in 1970 and that have been implemented pursuant to regulations promulgated in 1975 and followed in numerous subsequent CAA section 111 rulemakings. These requirements call on the EPA to develop emission guidelines that reflect

the EPA’s determination of the BSER for states to follow in formulating plans to implement standards of performance to

achieve emission reductions consistent with the BSER. In*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 46 of 1275 following the provisions, the EPA is finalizing a BSER based on strategies currently being used by states and companies to reduce CO 2 emissions from EGUs. 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 widely demonstrated availability of the trading of emission

rate credits or mass allowances as a mechanism to facilitate achievement by any individual EGU or group of EGUs of the emission reductions available from each of the building blocks, as well as to reduce costs, supports this approach. Any affected EGU can achieve the equivalent of dispatch of NGCC units, per building block 2, or of RE generation, per building block 3, by using the acquisition of a credit or allowance as the medium for investment in lower-emitting generation provided by NGCC units

or RE facilities. The CAA, as interpreted by the courts, identifies several

factors for the EPA to consider in a BSER determination. These include technical feasibility, costs, size of emission reductions and technology (e.g., whether the system promotes the implementation and further development of technology). In determining the BSER for this industrial sector, the EPA considered the reductions achievable through measures that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 47 of 1275

reduce CO 2 emissions from existing fossil fuel-fired EGUs either by (1) reducing the CO 2 emission rate at those units or (2) reducing the units’ CO 2 emission total to the extent that generation can be shifted from higher-emitting fossil fuel-fired EGUs to lower- or zero-emitting options. As the EPA has done in making BSER determinations in previous CAA section 111(d) rulemakings, 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 2 ) from affected sources (in this case, fossil fuelfired EGUs). 15 To determine the BSER for reducing CO 2 emissions at affected EGUs and to establish the emission guidelines that reflect the BSER, the EPA considered numerous measures that can and are being implemented to improve emission rates and

to reduce or limit mass CO 2 emissions from fossil fuel-fired EGUs. These measures encompass two basic approaches: 1)

15 The final emission guidelines for landfill gas emissions from municipal solid waste landfills, published on March 12, 1996 and amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, respectively r) are one example, as they allow either of two approaches for controlling landfill gas

– by recovering the gas as a fuel, for sale, and removing from the premises, or by destroying the organic content of the gas on the premises using a control device. Recovering the gas as a fuel source was a practice already being used by some affected sources prior to promulgation of the rulemaking.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 48 of 1275 reducing the carbon intensity of certain affected EGUs by improving the efficiency of their operations, and 2) addressing affected EGUs’ mass emissions by varying their utilization levels. For the second approach, we relied on the standard statutory and regulatory considerations that provide the basis for any BSER determination in examining, in this case, the extent to which that generation can be shifted from higher-emitting fossil fuel-fired EGUs to lower- or zero-emitting options. From these two approaches, we identified measures that fit into three main categories, or “building blocks.” The building blocks are: 1. Reducing the carbon intensity of generation at individual affected coal-fired steam EGUs through heat rate improvements.2. Substituting increased generation from loweremitting existing natural gas combined cycle units for reduced generation from higher-emitting affected steam generating units. 3. Substituting increased generation from new low- and zero-emitting generating units, including renewable energy and new natural gas combined cycle (NGCC) units, for reduced generation from affected fossil fuel-fired generating units.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 49 of 1275 The building blocks are described in detail in Section V of this preamble. As explained in that section, the EPA evaluated each of the building blocks individually against the BSER factors. The EPA found that each of the building blocks independently merits consideration as part of the BSER because, at the identified level of stringency, it is achievable by individual sources and by the source category, it will result in meaningful emission reductions at reasonable cost, and it satisfies the other BSER factors. This includes considering the use of some increment of new NGCC generation as part of building block 3, since replacing higher-emitting existing steam generation with cleaner new NGCC generation has been occurring to some degree. (For reasons discussed in Section V.A.3 of this preamble, the EPA determined not to finalize the inclusion of demand-side EE, which was discussed as a fourth potential building block in the proposal, as a component of the BSER.)

The EPA also evaluated combinations of the three building blocks against the BSER factors in making its

determination. The EPA determined that the combination of all three building blocks is the BSER, taking into account the fact that the widely demonstrated availability of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 50 of 1275 trading of emission rate credits or mass allowances can enable any given EGU to achieve its emission reduction obligations (i.e., if an EGU should choose not to meet its obligations simply by limiting its own operations, it could rely on the interconnected function of the electricity system to effectuate replacement generation from new clean generation or from the re-dispatch of existing NGCC units). This combination best represents the BSER because, compared to combinations including fewer than all three building blocks, it achieves greater emission reductions at a lower cost, takes better advantage of the wide range of measures that states, cities, towns and utilities are already using

to reduce CO 2 from EGUs, and reflects the integrated nature of the electricity system and the diversity of electricity generation technology. For the final rule, in response to stakeholder comments, the EPA has made refinements to the building blocks, and these are reflected in the final BSER. These include adoption of a modified approach to quantification of the renewable energy component, exclusion of the proposed nuclear generation components, and adoption of a consistent regionalized approach to quantification of all three building blocks. The BSER also

includes an increment of emission reductions at affected EGUs*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 51 of 1275 that corresponds to the increment of generation at new NGCC units projected to be built in the future that can replace generation at affected EGUs (e.g., generation from new NGCC units beyond what is needed to meet load growth and that is, therefore, available to displace existing, higher-emitting generation). 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 in a practical and reasonable cost way. 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 provide further information on the refinements made to the building blocks and the rationale for doing so. As part of the BSER determination, the EPA considered the impacts that implementation of the emission reductions

based on the combination of the blocks will have on the cost of electricity and electricity system reliability. As detailed in Section V of this preamble, the EPA believes that, both with respect to the overall BSER and with respect to the individual building blocks, the associated costs are reasonable. In summary, the EPA determined that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 52 of 1275 the BSER for purposes of CAA section 111(d), as applied to existing fossil fuel-fired EGUs, is based on a combination

of measures that reduce CO 2 emissions and CO 2 emission rates and encompasses three building blocks, together with emissions trading. 16 In determining the BSER, we considered the ranges of reductions that can be achieved at reasonable cost by application of each building block, considering both stringency and time, and we have calculated CO 2 emission performance rates for the categories of fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Rather than the maximum possible degree of application, we have finalized what we believe reflects a reasonable degree of application of each building block consistent with the BSER criteria. Relying on the three building blocks to characterize the

combination of measures that reduce CO 2 emissions and CO 2 emission rates at affected EGUs as the basis for the BSER is consistent with strategies, actions and measures that

16 The EPA notes that under the BSER, some building blocks will apply to some, but not all, affected sources. Specifically, building block 1 will apply to affected coal-fired steam EGUs, building block 2 will apply to all affected steam EGUs (both coal-fired and oil/gas-fired), and building block 3 will apply to all affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 53 of 1275 companies and states are already undertaking to reduce GHG emissions and with current trends in the utility power sector, driven by efforts to reduce GHGs as well as by other factors, such as advancements in technology. Reliance on all three building blocks in this way also supports the goals of achieving significant and technically feasible

reductions of CO 2 at a reasonable cost, while also promoting technology and approaches that are important for achieving further reductions. Finally, the EPA believes that the diverse range of measures encompassed in the three building blocks, and the availability of emissions trading, allows states and sources to take full advantage of the inherent flexibility of the current regionally interconnected and integrated electricity system so as to achieve the CO 2 goals while continuing to meet the demand for electricity

services in a reliable and affordable manner. The EPA recognizes that states differ in important ways, including in their mix of existing EGUs, policy priorities, and regional resource development opportunities. Consequently, opportunities for reducing emissions, as reflected in each of the building blocks, vary across states. Each state will be able to design a program that uses the measures it selects, and these may*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 54 of 1275 include the combination of building blocks most relevant to its specific circumstances and policy preferences. States may also use technologies or strategies that are not explicitly mentioned in any of the three building blocks and may use those technologies or strategies as part of their overall plans (e.g., market-based trading programs; demand-side energy efficiency programs). Explanation of other technologies or strategies that a state may incorporate in its plan is provided in Section VIII of thispreamble. Additionally, the EPA’s approach allows multistate strategies, ranging from the formal types of interstate arrangements (joint plans) to flexibility for sources in “trading ready” states to interact with one another through trading. These issues are discussed in greater detail in Section VIII.

e. CO 2 source category-specific emission performance rates and state-level goals. (1) Final CO 2 emission performance rates and goals. In this action, the EPA is establishing CO 2 emission performance rates for two subcategories of affected EGUs-- fossil fuel-fired electric utility steam generating units and stationary combustion turbines -- that state plans must be designed to meet. For fossil fuel-fired steam generating units, we are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 55 of 1275 finalizing an emission performance rate of 1,290 lb/MWh of CO 2 . For stationary combustion turbines, we are finalizing an emission performance rate of 780 lb/MWh of CO 2 . To continue to provide the flexibility inherent in the proposal’s state-specific goals approach, in this final rule, the EPA has translated the source category-specific

CO 2 emission performance rates into equivalent statewide

rate-based and mass-based CO 2 goals and is providing those in Section VII of this preamble. Affected EGUs, individually, in aggregate, or in combination with other measures undertaken by the state, must achieve the equivalent of the CO 2 emission performance rates by 2030. Importantly, by expressing the application of the final BSER as source category-specific CO 2 emission performance rates, and by providing a translation of those performance rates to statewide rate- and mass-based CO 2 goals, the rule allows states the flexibility to determine

how to achieve the CO 2 reductions (i.e., greater reductions from one building block and less from another, as well as the adoption of other measures that lower carbon intensity), and to adjust the timing in which reductions are achieved, in order to address key issues such as cost*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 56 of 1275 to consumers, electricity system reliability and the remaining useful life of existing generation assets. (2) Interim CO 2 emission performance rates and state-level goals. The EPA recognizes that, with many measures, states can

achieve CO 2 emission reductions in the short-term, in certain circumstances, such as those for which instrumental infrastructure and/or programs are already in place. For other measures, such as the addition of renewable energy (RE) generating capacity, the full effects of implementation can take longer. We recognize that, under the Clean Air Act, the determination of the BSER includes not only the types of measures that constitute the best system, but also the timeframe within which those measures can reasonably be implemented. In the proposal, we included an interim period – 2020 through 2029 – reflecting that reductions could reasonably be achieved on a glide path toward meeting the final goals in 2030. For the final emission guidelines, in response to concerns that required CO 2 emission reductions could not be achieved as early as 2020 – and to reflect the period of time required through the process of state plan development and submission to the EPA, the EPA review and approval and state and EGU implementation of approved plans - the EPA is establishing an eight-year interim period over which to achieve the full required reductions to meet the CO 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 57 of 1275 performance rates, and this begins in 2022, more than six years

from **[INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER],** the date of this rulemaking. This eight-year interim period from 2022 through 2029 is separated into three steps, 2022-2024, 2025-2027, and 2028-2029, each associated with its own interim

CO 2 emission performance rates. These steps respond to many comments we received requesting a more graduated trajectory, but the rule also retains a state’s ability to adapt these steps as appropriate to accommodate the timing of expected reductions, as long as the interim goal is met over the eight year period. A state can take advantage of this timing in the design of its program by using relevant combinations of building blocks, as well as averaging over the interim period, to achieve required

CO 2 reductions in a manner and on a schedule that provides for electricity system reliability, avoids the creation of stranded assets and bears a reasonable cost. In short, to use the parlance of numerous state and stakeholder discussions, states can determine their own respective emission reduction trajectories or “glide paths”. We believe that this approach for achieving CO 2 reductions over time responds both to the needs of an effectively implemented program and to the persuasive arguments presented by stakeholders regarding balancing the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 58 of 1275 simultaneous need for both flexibility and certainty about what will constitute an approvable state plan. We likewise believe that this approach also represents a reasonable balance between two competing objectives grounded in CAA section 111(d) - a need for rigor and consistency in calculating emission reductions reflecting the BSER and a need to provide the states with flexibility in establishing and implementing the emission standards or measures that reflect those emission reductions. The importance of this balance is heightened by the fact that the operations of the electricity system itself rely on the flexibility made available and achieved through shifting generation between and among multiple interconnected EGUs, demand management and demand-side energy efficiency. This approach recognizes that state plans for emission reductions can, and must, be consistent with a vibrant and growing economy and the ample supply of reliable, affordable electricity needed to support that economy. It further reflects the growing trend, as exemplified by many state and local clean energy policies and programs, to shift energy production away from carbon-intensive fuels to a modern, more sustainable system that puts greater reliance on renewable energy, energy efficiency and other low-carbon energy options.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 59 of 1275 f. State plans. 17 In this action, the EPA is also establishing final guidelines for states to follow in developing 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 2 emission reductions over time, and provide for monitoring and periodic reporting of progress. (1) Plan approaches. To comply with these emission guidelines, in its plan, each state will have to ensure that the emission standards it establishes for its sources individually, in aggregate, or in combination with other measures undertakenby the state, represent the equivalent of the source categoryspecific emission performance rates. This final rule includes several types of flexibilities for state plans, as discussed in the proposal and in many of the comments we received.

17 A state plan must be developed by a state, the District of Columbia, a U.S. territory, 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 if it has one or more affected EGUs in its jurisdiction. The District of Columbia does not have any affected EGUs and, therefore, will not be required to submit a plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 60 of 1275 First, under the final rule, states may adopt either a rate-based or mass-based goal. For this purpose, the EPA is providing statewide rate-based goals and mass-based goals equivalent to the emission performance rates that the EPA is establishing for the two subcategories of fossil fuel-fired EGUs. In developing its plan, each state, U.S. territory, and eligible tribe will need to choose whether it will include CO 2 emission performance rates, statewide rate-based goals, or statewide mass-based goals. The second major flexibility provided in the final rule relates to the types of measures included in the state plans. A state will be able to choose to place all of the requirements directly on its affected EGUs, which we refer to as the “emission standards approach.” Alternatively, a state can adopta “state measures approach,” which would include stateenforceable measures that may apply to affected EGUs and other entities, with some or no federally enforceable emission standards for affected EGUs. With a state measures approach, the plan must also include a backstop of federally enforceable standards on affected EGUs that fully meet the emission guidelines and that would be triggered if the plan failed to achieve on schedule the required emission reductions. A state would have the option of basing its backstop emission standards*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 61 of 1275 on the federal plan, using the federal plan regulations as a

model rule. The plan must also include a process for reporting on plan implementation, progress toward achieving CO 2 emission reductions, and implementation of corrective actions, if applicable. Beginning January 1, 2025, and then January 1, 2027, followed by January 1, 2029, and then every two calendar years, the state will be required to compare emission levels achieved by affected EGUs in the state with the emission levels projected in the state plan and report the results of that comparison to the EPA by July 1 of those calendar years. Plans for states with existing programs, such as those being implemented in California and the RGGI states, will be approvable provided that, when plans are submitted, they demonstrate that when the plans are fully implemented,

affected EGUs achieve all of the emission reductions required in these guidelines for those states’ sources that are affected per these guidelines. The plan guidelines provide the states with the ability to achieve the full reductions over a multi-year period, through a variety of reduction strategies, using state-specific or multi-state approaches that can be achieved on either a rate or mass basis. They also address several key policy considerations*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 62 of 1275 that states can be expected to contemplate in developing their plans. State plan approaches and plan guidelines are explained further in Section VIII of this preamble. (2) State plan components and approvability criteria. The EPA’s implementing regulations provide certain basic elements required for state plans submitted pursuant to CAA section 111(d). 40 CFR 60.23. In the proposal, the EPA identified

certain additional elements that should be contained in state plans. In this final action, in response to comments, the EPA is making several revisions to the components required in a state plan submittal and is also incorporating the approvability criteria into the list of components required in a state plan submittal. In addition, we have revised the state plan components to reflect: 1) components required for all state plan submittals; 2) additional components required for the emission standards approach; and 3) additional components required for the state measures approach. All state plans must include the following components:

 Description of the plan

 Identification of state CO 2 interim period goal (for 2022-2029), interim steps (interim step goal 1 for 2022-2024; interim step goal 2 for 2025-2027; interim step goal 3 for 2028-2029) and final CO 2 emission goal of 2030 and beyond

 Demonstration that the plan submittal is projected to achieve the state ’ s CO 2 emission goal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 63 of 1275

 State recordkeeping and reporting requirements

 Certification of hearing on state plan

 Supporting documentation Also, in submitting state plans, states must provide documentation demonstrating that they have considered reliability in developing their plans. Further, because certain communities, including low-income communities and some communities of color, are disproportionately affected by climate change related impacts, the EPA is seeking to ensure that states are actively engaging with communities and is, therefore, requiring states to provide, in their initial plan submittal, a summary of how they have been engaging with community stakeholders and how they intend to meaningfully engage with community stakeholders during the additional time (if an extension is granted) for development of the final plan. For the final plan submittal, states must have meaningful engagement with all members of the public, including affected communities, during the final plan development process, pursuant to the public participation requirements of the implementing regulations. This could include topics such as potential localized impacts and potential changes to electricity rates, among others. State plan submittals using the emission standards approach

must also include:*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 64 of 1275

 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. (3) Timing and process for state plan submittal and review. 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. Commenters have provided compelling information that it will take longer than the agency initially anticipated to adjust investments and

achieve interim CO 2 reductions. The EPA agrees with these comments, which we believe support extending the start date of the compliance period from 2020 to 2022 and retaining the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 65 of 1275 requirement that initial plans be submitted without additional delay. Specifically, the final rule requires each state to submit a plan by August 31, 2016. Since some states may need more than one year to complete all of the actions needed for their final state plans, including technical work, state legislative and rulemaking activities, a robust public participation process, coordination with third parties, and coordination among states involved in multi-state plans, as well as consultation with reliability entities, the EPA is allowing an optional two-phased submittal process for state plans. Each state will be required to submit a plan by August 31, 2016, that contains certain required components. If a state needs additional time to submit a final plan, then the state may submit an initial plan by August 31, 2016, that documents the

reasons the state needs more time and includes commitments to concrete steps that will ensure that the state will submit a final plan by August 31, 2018. To be approvable, the EPA is finalizing that the initial plan submittal must address all components of a final plan submittal, including identifying which components are not complete. The initial plan must include specific components, including a justification for seeking an extension, a description of the plan approach, a commitment to maintain existing measures that limit CO 2 emissions, progress to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 66 of 1275 date in developing a final plan, a comprehensive roadmap of the path to completion including specific steps the state, sources or other entities will be implementing in order to meet the initial compliance requirements beginning in 2022, and demonstration of opportunity for public comment on the submittal and a summary of the state’s response to any significant public comment on the approvability of the initial plan, as described in Section VIII.E of this preamble. 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, the extension of time to submit a final plan will be deemed granted and a state will have until August 31, 2018, to submit a final plan. Further, states participating in a multi-state plan may submit a single joint plan on behalf of all of the participating states. States, U.S. territories, and tribes that do not have affected EGUs in their jurisdictional boundaries may participate in emission trading programs (e.g., as providers of emission rate credits, to adjust CO 2 emission rates for affected EGUs). Following submission of final plans, the EPA will review plan submittals for approvability. Given the diverse approaches states may take to meet the CO 2 emission performance rates or equivalent statewide goals in the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 67 of 1275 emission guidelines, the EPA is extending the period for EPA review and approval or disapproval of plans from the four-month period provided in the EPA implementing regulations to a twelve-month period. (4) Timing for meeting the CO 2 emission guidelines. The EPA recognizes that the measures states and utilities have been and will be taking to reduce CO 2 emissions from existing EGUs can take time to implement. Based on a careful review of the comments and other material in the record, the EPA is determining in this final rule that affected EGUs will be required to begin to make reductions by 2022, instead of 2020, as proposed, and meet the final CO 2 performance rates or equivalent statewide goals by no later than 2030. The EPA is establishing an eight-year interim period that begins in 2022 and goes through 2029, and which is separated into three steps, 2022-2024, 2025-2027, and 2028-2029, each associated with its own interim goal. Affected EGUs must meet each of the interim period step 1, 2, and 3 CO 2 performance rates, or must meet the equivalent statewide interim period goals, on average, that a state may establish over the 8-year period from 2022-2029, which the state must reflect in its CAA section 111(d) plan. Affected

EGUs must also achieve the final CO 2 performance rates or the equivalent statewide goal by 2030 and maintain that level*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 68 of 1275 subsequently. This approach reflects adjustments to the

timeframe over which reductions must be achieved that mirror the determination of the final BSER. The agency believes that this approach for timing is reasonable and appropriate, is consistent with many of the comments we received, and will best support the optimization of overall CO 2 reductions. Measures that a state takes prior to 2022, or programs already in place by 2022, that result in CO 2 emission reductions during the 2022-2029 period will contribute toward meeting both

the interim and final CO 2 emission performance rates. Thus, states with currently existing programs and policies, and states that put in place new programs and policies early, will be better positioned to achieve the goals. RE generating capacity

and demand-side EE measures that are installed after 2012 will be eligible for use in adjusting a CO 2 emission performance rate. Further discussion of timing is presented in Section VIII.G of this preamble. (5) Electric system reliability. These guidelines reflect the paramount importance of ensuring electric system reliability, 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. We are addressing these concerns in large part by moving*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 69 of 1275 the start date of the program from 2020 to 2022 and significantly adjusting the interim goals so that they provide a less abrupt initial reduction expectation. These changes will provide 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. 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. In addition, we are including in the final rule a requirement that each state demonstrate in its state plan submittal that it has considered reliability issues in developing its plan, which it can do, for example, by consulting with state utility agencies and/or regional planning authorities. 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 further provide states with the option of proposing amendments to approved plans in the event that unanticipated and significant reliability challenges arise. And, as a final element of reliability assurance, the rule also*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 70 of 1275 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 due to an extraordinary event. In addition, 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 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 2 emissions under this program. (6) Outreach and resources for stakeholders. 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, and stakeholders to provide*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 71 of 1275 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 10 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 officials. 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 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 the Clean Power Plan. Recorded presentations from the EPA, DOE and other federal entities will be available for communities, states, and others involved in composing and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 72 of 1275 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 the U.S. Department of Energy and other federal agencies, will continue

to make these resources available via a dedicated website. 18 We intend to continue to work actively with states, U.S. territories and tribes to provide information and technical support that will be helpful to them in developing and implementing their plans. 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. 5. Projected national-level emission reductions Under the final guidelines, the EPA projects annual CO 2 reductions of [X} percent below 2005 levels in 2020, [X} percent below 2005 levels in 2025, and [X] percent below 2005 levels in 2030. These guidelines will also result in important reductions in emissions of criteria air pollutants, including sulfur dioxide (SO 2 ), nitrogen oxides (NO X ), and directly emitted fine particulate matter (PM 2.5 ).

18 www.epa.gov/cleanpowerplantoolbox.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 73 of 1275 A thorough discussion of the EPA’s analysis is presented in Section XI.A of this preamble and in Chapter 3 of the Regulatory Impact Analysis (RIA) included in the docket for this rulemaking.

6. Costs and benefits Actions taken to comply with the final guidelines will

reduce emissions of CO 2 and other air pollutants, including

SO 2 , NO X , and directly emitted PM 2.5 from the utility power

sector. States will make the ultimate determination as to how the emission guidelines are implemented. Thus, all costs and benefits reported for this action are

illustrative estimates. The illustrative costs and benefits are based upon compliance approaches that reflect a range of measures consisting of improved operations at EGUs, dispatching lower-emitting EGUs and zero-emitting energy sources, and increasing levels of end-use energy efficiency. The EPA estimates that, in 2020, the final guidelines will yield monetized climate benefits of approximately $[X] billion (2011$) using a 3 percent discount rate (model average) relative to the 2020 base case (Table 1). 19 The air pollution health co-

19 The EPA has used social cost of carbon (SCC) estimates — i.e., the monetary value of impacts associated with a marginal change*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 74 of 1275 benefits associated with reducing exposure to ambient PM 2.5 and ozone through emission reductions of precursor pollutants in 2025 relative to the 2020 base case are estimated to be $[X] billion to $[X] billion using a 3 percent discount rate and $[X] billion to $[X] billion (2011$) using a 7 percent discount rate. In 2025, the final guidelines will yield monetized climate benefits of approximately $[X] billion (2011$) using a 3 percent discount rate (model average) relative to the 2025 base case (Table 1). The air pollution health co-benefits in 2025 relative to the 2025 base case are estimated to be $[X] billion to $[X] billion using a 3 percent discount rate and $[X] billion to $[X] billion (2011$) using a 7 percent discount rate. In 2030, the EPA estimates the final guidelines will yield monetized climate benefits of approximately $[X] billion (2011$) using a 3 percent discount rate (model average) relative to the 2030. The air pollution health co-benefits in 2030 relative to the 2030 base case are estimated to be $[X] billion to $[X]

in CO 2 emissions in a given year — to analyze the benefits from changes in CO 2 emissions expected from this rulemaking. The four SCC estimates are associated with different discount rates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent), and each increases over time. In this summary, the EPA provides the estimate of climate benefits associated with the SCC value deemed to be central: the model average at 3 percent discount rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 75 of 1275 billion using a 3 percent discount rate and $[X] billion to $[X] billion (2011$) using a 7 percent discount rate. The annual compliance costs are estimated using the Integrated Planning Model (IPM) and include demand-side energy efficiency program and participant costs as well as monitoring, reporting and recordkeeping costs. In 2020, total compliance costs of the final guidelines are approximately $[X] billion (2011$). In 2025, total compliance costs of the final guidelines are approximately $[X] billion (2011$). In 2030, total compliance costs of the final guidelines are approximately $[X] billion (2011$). The quantified net benefits (the difference between monetized benefits and compliance costs) in 2020 are estimated to range from $[X] billion to $[X] billion (2011$) using a 3 percent discount rate (model average). In 2025, the quantified net benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated to range from $[X] billion to $[X] billion (2011$) using a 3 percent discount rate (model average). In 2030, the quantified net benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated to range from $[X] billion to $[X] billion (2011$) using a 3 percent discount rate (model average).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 76 of 1275 **Table 1. Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Final Guidelines in 2020, 2025, and** 

**2030 a**  **[Billions of 2011$]**

**Final Guidelines, 2020 3% Discount Rate 7% Discount rate**  **Climate benefits b**  $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X] **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment **Final Guidelines, 2025 3% Discount rate 7% Discount rate**  **Climate benefits b**  $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X] **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 77 of 1275 **Final Guidelines, 2030 Climate benefits**  **b** $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X] **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment

a All are rounded to two significant figures, so figures may not sum. b The climate benefit estimate in this summary table reflects global impacts from CO 2 emission changes and does not account for changes in non-CO 2 GHG emissions. Also, different discount rates are applied to SC-CO 2 than to the other estimates because CO 2 emissions are long-lived and subsequent damages occur over many years. The benefit estimates in this table are based on the average SCC estimated for a 3% discount rate, however we emphasize the importance and value of considering the full range of SC-CO 2 values. As shown in the RIA, climate benefits are also estimated using the other three SC-CO 2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). The SC-CO 2 estimates are year-specific and increase over time.

c The air pollution health co-benefits reflect reduced exposure to PM 2.5 and ozone associated with emission reductions of directly emitted PM 2.5 , SO 2 and NO X . The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM 2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. d Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 78 of 1275 final guidelines and a discount rate of approximately 5%. This estimate includes monitoring, recordkeeping, and reporting costs and demand side energy efficiency program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO 2 at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on additional discount rates. 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 2 emissions do not include important impacts like ocean acidification or potential tipping points in natural or managed ecosystems. The unquantified benefits also include climate benefits from reducing emissions of non-CO 2 greenhouse gases (e.g., nitrous oxide and methane) 20 and cobenefits from reducing direct exposure to SO 2 , NO X , and hazardous air pollutants (e.g., mercury and hydrogen chloride), as well as from reducing ecosystem effects and visibility impairment. We project employment gains and losses relative to base case for different types of labor, including

20 Although CO 2 is the predominant greenhouse gas released by the power sector, electricity generating units also emit small amounts of nitrous oxide and methane. For more detail about power sector emissions, see RIA Chapter 2 and the U.S. Greenhouse Gas Reporting Program’s power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm l.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 79 of 1275 construction, plant operation and maintenance, coal and natural gas production, and demand side energy efficiency. In [X], we project a net change of [X] job-years 21 for construction, plant operation and maintenance, and coal and natural gas and [X] jobs in the demand-side energy efficiency sector. Actual employment impacts will depend upon measures taken by states in their state plans and the specific actions sources take to comply. Based upon the foregoing, it is clear that the monetized benefits of this rule are substantial and far outweigh the

costs. B. Organization and Approach for this Rule

This final rule establishes the EPA’s emission guidelines for states to follow in developing plans to reduce CO 2 emissions from the utility power sector. Section II of this preamble provides background information on climate change impacts from GHG emissions, GHG emissions from fossil fuel-fired EGUs, the utility power sector, the CAA section 111(d) requirements, EPA actions prior to this final action, outreach and consultations,

and the number and extent of comments received. In Section III

21 A job-year is not an individual job; rather, a job-year is the amount of work performed by the equivalent of one full-time individual for one year. For example, 20 job-years in 2025 may represent 20 full-time jobs or 40 half-time jobs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 80 of 1275 of the preamble, we present a summary of the rule requirements and the legal basis for these. Section IV explains the EPA authority to regulate CO 2 and EGUs, identifies affected EGUs, and describes the proposed treatment of source categories. Section V describes the agency’s determination of the BSER using four building blocks for setting state goals and our key considerations in doing so. Section VI provides the source category-specific emission performance rates, and Section VII provides equivalent statewide rate-based and mass-based goals. Section VIII then describes state plan approaches and the requirements, and flexibilities, for state plans, followed by Section IX, in which considerations for communities are

described. Interactions between this final rule and other EPA programs and rules are discussed in Section X. Impacts of the proposed action are then described in Section XI, followed by a discussion of statutory and executive order reviews in Section XII and the statutory authority for this action in Section XII. We note that this rulemaking is being promulgated concurrently with a related rulemaking, the final new source performance standards (NSPS) for CO 2 emissions from newly constructed, modified, and reconstructed EGUs **[INSERT THE FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE RULE]**  ,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 81 of 1275 which is being promulgated under CAA section 111(b). This rulemaking has its own rulemaking docket.

**II. Background**  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, explain the uniqueness of the utility power sector and describe recent and continuing trends and transitions in this sector. In addition, we briefly provide highlights of Congressional awareness of climate change and international agreements and actions, and summarize the 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, 22 followed by information on stakeholder outreach and consultations and the comments that the EPA received prior to issuing this final rulemaking. A. Climate Change Impacts from GHG Emissions

22 The EPA also published in the Federal Register a notice of data availability (79 FR 64543; November 8, 2014) and a notice on the translation of emission rate-based CO 2 goals to mass-based equivalents (79 FR 67406; November 13, 2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 82 of 1275 According to the National Research Council, “Emissions

of CO 2 from the burning of fossil fuels have ushered in a new epoch where human activities will largely determine the

evolution of Earth’s climate. Because CO 2 in the atmosphere is long lived, it can effectively lock Earth and future generations into a range of impacts, some of which could become very severe. Therefore, emission reduction choices made today matter in determining impacts experienced not just over the next few decades, but in the coming centuries

and millennia.” 23 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). 24 In the Endangerment Finding, the Administrator found that the current, elevated concentrations of GHGs in the atmosphere—already at levels unprecedented in human history—may reasonably be anticipated to endanger public health and welfare of current and future generations in the United States. We summarize these adverse effects on public health and welfare briefly here.

23 National Research Council, Climate Stabilization Targets, p.3. 24 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 83 of 1275 1. Public health impacts detailed in the 2009 Endangerment Finding 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., including 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. 2. Public welfare impacts detailed in the 2009 Endangerment Finding*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 84 of 1275 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 21 st 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 85 of 1275 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.

3. New scientific assessments and observations 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 2 concentrations, and sea level rise. Additionally, a number of major scientific assessments have been released that improve understanding of the climate system and strengthen the case that GHGs endanger public health and welfare both for current and future generations. These assessments, from the Intergovernmental Panel on Climate Change (IPCC), the U.S. Global Change Research Program (USGCRP), and the National Research Council (NRC), include: IPCC’s 2012 Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 National Climate Assessment, Climate Change Impacts in the

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean

(Ocean Acidification), 2011 Report on Climate Stabilization*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 86 of 1275 Targets: Emissions, Concentrations, and Impacts over Decades to

Millennia (Climate Stabilization Targets), 2011 National Security Implications for U.S. Naval Forces (National Security Implications), 2011 Understanding Earth’s Deep Past: Lessons for

Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future , 2012 Climate and Social Stress: Implications for Security Analysis (Climate and Social Stress),

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts)

assessments. 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 87 of 1275 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 mentalhealth, and illnesses transmitted by food, water, and diseasecarriers 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 2 by itself can elevate production of plant-based allergens. 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 (e.g., permafrost thaw, effects on traditional food sources) have significant impacts, observed now and projected, on the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 88 of 1275 health and well-being of Arctic residents, especially indigenous peoples. Small, remote, predominantly-indigenous communities are especially vulnerable given their “strong dependence on the environment for food, culture, and way of life; their political and economic marginalization; existing social, health, and poverty disparities; as well as their frequent close proximity to exposed locations along ocean, lake, or river shorelines.” 25 In addition, increasing temperatures and loss of Arctic sea ice increases the risk of drowning for those engaged in traditional hunting and fishing. 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

25 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, p. 1581.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 89 of 1275 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 Understanding Earth’s Deep Past projected that, without a reduction in emissions, CO 2 concentrations by the end of the century would increase to levels that the Earth has not experienced for more than 30 million years. 26 In fact, that assessment stated that

26 National Research Council, Understanding Earth’s Deep Past, p. 1.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 90 of 1275 “the magnitude and rate of the present greenhouse gas increase place the climate system in what could be one of the most severe increases in radiative forcing of the global climate system in Earth history.” 27 Because of these unprecedented changes, several assessments state that we may be approaching critical, poorly

understood thresholds: as stated in the NRC assessment Understanding Earth’s Deep Past, “As Earth continues to warm, it may be approaching a critical climate threshold beyond which rapid and potentially permanent—at least on a human timescale— changes not anticipated by climate models tuned to modern conditions may occur.” Moreover, due to the time lags inherent in the Earth’s climate, the NRC Climate Stabilization Targets assessment notes that the full warming from any given

concentration of CO 2 reached will not be fully realized for several centuries, underscoring that emission activities today carry with them climate commitments far into the future. 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,

27 Id., p.138.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 91 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 92 of 1275 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 4 th 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,” 28 and the NRC Climate Stabilization Targets assessment states that an increase of 3°C will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3

28 NRC, 2011: National Security Implications of Climate Change for U.S. Naval Forces . The National Academies Press, p. 28.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 93 of 1275 feet) by 2100. These assessments continue to recognize that there is uncertainty inherent in accounting for ice sheet processes. Additionally, local sea level rise can differ from the global total depending on various factors: the east coast of the U.S. in particular is expected to see higher rates of sea level rise than the global average. For comparison, the NCA3

states that “five million Americans and hundreds of billions of dollars of property are located in areas that are less than four feet above the local high-tide level,” and the NCA3 finds that “[c]oastal infrastructure, including roads, rail lines, energy infrastructure, airports, port facilities, and military bases, are increasingly at risk from sea level rise and damaging storm surges.” 29 Also, because of the inertia of the oceans, sea level rise will continue for centuries after greenhouse gas concentrations have stabilized (though more slowly than it would have otherwise). Additionally, there is a threshold temperature

above which the Greenland ice sheet will be committed to inevitable melting: according to the NCA, some recent research has suggested that even present day carbon dioxide levels could

be sufficient to exceed that threshold.

29 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, p. 9.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 94 of 1275 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 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 United States. 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.” 30 The IPCC AR5 notes, “Climate-related hazards exacerbate other stressors, often with negative outcomes for livelihoods, especially for people living in poverty (high confidence). Climate-related hazards affect poor people’s lives directly through impacts on livelihoods, reductions in crop yields, or

30 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, p. 17.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 95 of 1275 destruction of homes and indirectly through, for example, increased food prices and food insecurity.” 31 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% more acidic over the past 250 years due to absorption of CO 2 from the atmosphere. According to the NCA3, this acidification will reduce the ability of organisms such as corals, krill, oysters, clams, and crabs to survive, grow, and reproduce. The NRC Understanding Earth's Deep Past assessment notes four of the five major coral reef crises of the past 500 million years were caused by acidification and warming that followed GHG increases of similar magnitude to the emissions increases expected over the next hundred years. Similarly, the NRC Ocean Acidification assessment finds that “[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxide emissions; the rate of change exceeds any known

31 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, p. 796.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 96 of 1275 to have occurred for at least the past hundreds of thousands of years.” 32 The assessment notes that the full range of consequences is still unknown, but the risks “threaten coral reefs, fisheries, protected species, and other natural resources of value to society.” 33 Events outside the United States, 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

32 NRC, 2010: Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean . The National Academies Press, p. 5. 33 Ibid.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 97 of 1275 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% probability) that human influence was the dominant cause of the observed warming since the mid-20 th century, and likely (>66% 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 98 of 1275 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 2 as measured on top of Mauna Loa was 387 parts per million, far above preindustrial concentrations of about 280 parts per million. 34 The average concentration in 2013, the last full year before this rule was proposed, was 396 parts per million. The average concentration in 2014 was 399 parts per million. And the monthly concentration in April of 2014 was 401 parts per million, the first time a monthly average has exceeded

34 ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx t*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 99 of 1275 400 parts per million since record keeping began at Mauna Loa in 1958, and for at least the past 800,000 years. 35 Arctic sea ice has continued to decline, with September of 2012 marking a new record low in terms of Arctic sea ice extent, 40 percent below

the 1979-2000 median. Sea level has continued to rise at a rate of 3.2 mm per year (1.3 inches/decade) since satellite observations started in 1993, more than twice the average rate

of rise in the 20 th century prior to 1993. 36 And 2014 was the warmest year globally in the modern global surface temperature record, going back to 1880; this now means 19 of the 20 warmest years have occurred in the past 20 years, and except for 1998, the ten warmest years on record have occurred since 2002. 37 The

first months of 2015 have also been some of the warmest on

record. 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

35 http://www.esrl.noaa.gov/gmd/ccgg/trends/ 36 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238. 37 http://www.ncdc.noaa.gov/sotc/global/2014/13*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 100 of 1275 begin the process of substantially reducing emissions.” 38 For example:

 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.

4. Observed and Projected U.S. Regional Changes The NCA3 assessed the climate impacts in 8 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,

38 NRC, 2011: America’s Climate Choices , The National Academies Press.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 101 of 1275 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%),

and sea level rise of about a foot has led to an increase in coastal flooding. The 70% increase in the amount of rainfall falling in the 1% of the most intense events is a larger increase in extreme precipitation than experienced in any other US 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 102 of 1275 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 103 of 1275 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 groundlevel 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 United States, 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 o 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 104 of 1275 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 o F to 9.7 o F by the end of the century (depending on future global greenhouse gas emissions), with the greatest warming is expected during the summer. Continued increases in global greenhouse gas emissions are projected to result in up to a 30% 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 105 of 1275 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 greenhouse gas 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 106 of 1275 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 if 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 107 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 108 of 1275 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 (e.g., heat waves and flooding) have already increased in frequency and/or intensity due to climate change. 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 longterm decreases in agricultural productivity, changes in the composition of the region’s forests, increased public health*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 109 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 110 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 111 of 1275 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% since the pre-industrial era and is projected to further increase by 37% to 50% 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.

B. GHG Emissions from Fossil Fuel-fired EGUs 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 2 , and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. This section describes the amounts of these emissions and places*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 112 of 1275 these amounts in the context of the U.S. Inventory of Greenhouse

Gas Emissions and Sinks 39 (the U.S. GHG Inventory). The EPA implements a separate program under 40 CFR Part 98 called the Greenhouse Gas Reporting Program 40 (GHGRP) that requires emitting facilities over threshold amounts of GHGs to report their emissions to the EPA annually. Using data from the GHGRP, this section also places emissions from fossil fuel-fired EGUs in the context of the total emissions reported to the GHGRP from facilities in the other largest-emitting industries. 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 2 below, which presents total U.S. anthropogenic emissions and sinks 41 of GHGs, including CO 2 emissions, for the years 1990, 2005 and 2013.

39 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 40 U.S. EPA Greenhouse Gas Reporting Program Dataset, see http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html 41 Sinks are a physical unit or process that stores GHGs, such as forests or underground or deep sea reservoirs of carbon dioxide.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 113 of 1275 **Table 2. U.S. GHG Emissions and Sinks by Sector (million metric tons carbon dioxide equivalent (MMT CO**  **2 Eq.))**  **42**

**SECTOR 1990 2005 2013** Energy 43 5,290.5 6,273.6 5,636.6

Industrial Processes and Product Use 342.1 367.4 359.1 Agriculture 448.7 494.5 515.7 Land Use, Land-Use Change and Forestry 1 3.8 2 5.5 2 3.3

Waste 206.0 189.2 138.3 Total Emissions 6,301.1 7,350.2 6,673.0 Land Use, Land-Use Change and Forestry (Sinks) (775.8) (911.9) (881.7) Net Emissions (Sources and Sinks) 5,525.2 6,438.3 5,791.2 Total fossil energy-related CO 2 emissions (including both stationary and mobile sources) are the largest contributor to total U.S. GHG emissions, representing 77.3 percent of total

2013 GHG emissions. 44 In 2013, fossil fuel combustion by the

42 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 43 The energy sector includes all greenhouse gases resulting from stationary and mobile energy activities, including fuel combustion and fugitive fuel emissions. 44 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15, 2015.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 114 of 1275 utility power sector –- entities that burn fossil fuel and whose primary business is the generation of electricity –- accounted for 38.3 percent of all energy-related CO 2 emissions. 45 Table 3 below presents total CO 2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 and 2013. **Table 3. U.S. GHG Emissions from Generation of Electricity from Combustion of Fossil Fuels (MMT CO**  **2 )**  **46**

In addition to preparing the official U.S. GHG Inventory to present comprehensive total U.S. greenhouse gas emissions and comply with commitments under the UNFCCC, the EPA collects detailed GHG emissions data from the largest emitting facilities

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 45 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 46 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States Environmental Protection Agency, April 15 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. **GHG EMISSIONS 1990 2005 2013**

Total CO 2 from fossil fuelfired EGUs 1 ,820.8 2 ,400.9 2,039.8

- from coal 1 ,547.6 1,983.8 1,575.0 - from natural gas 1 75.3 3 18.8 441.9 - from petroleum 9 7.5 9 7.9 22.4*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 115 of 1275 in the U.S. through its Greenhouse Gas Reporting Program (GHGRP). Data collected by the GHGRP from large stationary sources in the industrial sector show that the utility power sector emits far greater CO 2 emissions than any other industrial sector. Table 4 below presents total GHG emissions in 2013 for the largest emitting industrial sectors as reported to the GHGRP. As shown in Table 3 and Table 4, respectively, CO 2 emissions from fossil fuel-fired EGUs are nearly three times as large as the total reported GHG emissions from the next ten largest emitting industrial sectors in the GHGRP database

combined. **Table 4. Direct GHG Emissions Reported to GHGRP by Largest Emitting Industrial Sectors (MMT CO**  **2 e)**  **47**

C. The Utility Power Sector

1. A brief history

47 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.

**Industrial Sector 2013** Petroleum Refineries 176.7 Onshore Oil & Gas Production 94.8 Municipal Solid Waste Landfills 9 3.0 Iron & Steel Production 8 4.2 Cement Production 62.8 Natural Gas Processing Plants 59.0 Petrochemical Production 52.7 Hydrogen Production 41.9 Underground Coal Mines 39.8 Food Processing Facilities 30.8*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 116 of 1275 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, 48 electricity has become one of the major foundations for modern American life. Beginning with the first power station in New York City in 1882, each power station initially served a discrete set of consumers, resulting in small and localized electricity systems. 49 During the early 1900s, smaller systems consolidated, allowing generation resources to be shared over larger areas. Interconnecting systems have reduced generation investment costs and improved reliability. 50 Local and state governments initially regulated these growing electricity

48 Regulatory Assistance Project (RAP), Electricity Regulation in the US: A Guide , at 1 (2011), available at http://www.raponline.org/document/download/id/645. 49 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 2-4 (2d ed. 2010). 50 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 5-6 (2d ed. 2010). Investment in electric generation is extremely capital intensive, with generation potentially accounting for 65 percent of customer costs. If these costs can be spread to more customers, then this can reduce the amount that each individual customer pays. Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 117 of 1275 systems with federal regulation coming later in response to public concerns about rising electricity costs. 51 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. 52 During this time period, the U.S. Supreme Court found that state authority to regulate public utilities is limited, holding that the Commerce Clause does not allow state regulation to directly burden interstate commerce. 53 For example, in Public Utilities Commission of Rhode Island v. Attleboro Steam & Electric Company , Rhode Island sought to regulate the electricity rates that a Rhode Island generator was charging to a company in Massachusetts that resold the electricity to Attleboro, Massachusetts. 54 The Supreme Court found that Rhode Island’s regulation was impermissible because

51 Burn, An Energy Journal, The Electricity Grid: A History , available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). 52 The FPC became an independent Commission in 1930. United States Government Manual 1945: First Edition , at 486, available at http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html. 53 New York v. Federal Energy Regulatory Commission , 535 U.S. 1, 5 (2002) (citation omitted). 54 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & Elec. Co., 273 U.S. 83 (1927).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 118 of 1275 it imposed a "direct burden upon interstate commerce." 55 The Supreme Court held that this kind of interstate transaction was not subject to state regulation. However, because Congress had not yet passed legislation to make these types of transactions subject to federal regulation, this became known as the

" Attleboro gap" in regulation. In 1935, Congress passed the Federal Power Act (FPA), giving the FPC jurisdiction over “the transmission of electric energy in interstate commerce" and "the sale of electric energy at wholesale in interstate commerce." 56 Under FPA section 205, the FPC was tasked with ensuring that rates for jurisdictional services are just, reasonable, and not unduly discriminatory or preferential. 57 FPA section 206 authorized the FPC to determine, after a hearing upon its own motion or in response to a complaint filed at the Commission, whether jurisdictional rates are just, reasonable, and not unduly discriminatory or preferential. 58 In 1938, Congress passed the Natural Gas Act (NGA), giving the FPC jurisdiction over the transmission or sale of natural gas in interstate commerce. 59 The

55 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & Elec. Co., 273 U.S. 83, 89 (1927). 56 16 U.S.C. § 824(b)(1). 57 16 U.S.C. § 824d. 58 16 U.S.C. § 824e. 59 Energy Information Administration, Natural Gas Act of 1938 , available at*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 119 of 1275 NGA also gave the FPC the jurisdiction to “grant certificates allowing construction and operation of facilities used in interstate gas transmission and authorizing the provision of

services.” 60 In 1977, the FPC became FERC after Congress passed the Department of Energy Organization Act. By the 1930s, regulated electric utilities that provided the major components of the electrical system - generation, transmission, and distribution - were common. 61 These regulated monopolies are referred to as vertically-integrated utilities. As utilities built larger and larger electric generation plants, the cost per unit to generate electricity decreased. 62 However, these larger plants were extremely capital intensive for any one company to fund. 63 Some neighboring utilities solved this issue by agreeing to share electricity reserves when

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm ajorleg/ngact1938.html. 60 Energy Information Administration, Natural Gas Act of 1938 , available at http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm ajorleg/ngact1938.html. 61 Burn, An Energy Journal, The Electricity Grid: A History , available at http://burnanenergyjournal.com/the-electric-grid-ahistory/(last visited Mar. 9, 2015). 62 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 63 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 120 of 1275

needed. 64 These utilities began building larger transmission lines to deliver power in times when large generators experienced outages. 65 Eventually, some utilities that were in reserve sharing agreements formed electric power pools to balance electric load over a larger area. Participating utilities gave control over scheduling and dispatch of their electric generation units to a system operator. 66 Some power pools evolved into today’s regional transmission organizations (RTOs) and independent system operators (ISOs). In the past, electric utilities generally operated as state regulated monopolies, supplying end-use customers with generation, distribution, and transmission service. 67 However, the ability of electric utilities to operate as natural monopolies came with consumer protection safeguards. 68 “In

64 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 65 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 66 Shively, B, Ferrare, J, Understanding Today’s Electricity Business , Enerdynamics, at 94 (2012). 67 Maryland Department of Natural Resources, Maryland Power Plants and the Environment: A Review of the Impacts of Power Plants and Transmission Lines on Maryland’s Natural Resources , at 2-5 (2006). 68 Pacific Power, Utility Regulation , at 1, available at https://www.pacificpower.net/content/dam/pacific_power/doc/About _Us/Newsroom/Media_Resources/Regulation.PP.08.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 121 of 1275 exchange for a franchised, monopoly service area, utilities accept an obligation to serve – meaning there must be adequate supply to meet customers’ needs regardless of the cost.” 69 Under this obligation to serve, the utility agreed to provide service to any customer located within its service jurisdiction. On both a federal and state level, competition has entered the electricity sector to varying degrees in the last few

decades. 70 In the early 1990s, some states began to consider allowing competition to enter retail electric service. 71 Federal and state efforts to allow competition in the electric utility industry have resulted in independent power producers (IPPs) 72

69 Pacific Power, Utility Regulation , at 1, available at https://www.pacificpower.net/content/dam/pacific_power/doc/About _Us/Newsroom/Media_Resources/Regulation.PP.08.pdf. 70 For example, in 1978, Congress passed the Public Utilities Regulatory Policies Act (PURPA) which allowed non-utility owned power plants to sell electricity. Burn, An Energy Journal, The Electricity Grid: A History , available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015). PURPA, the Energy Policy Act of 1992 (EPAct 1992), and the Energy Policy Act of 2005 (EPAct 2005) “promoted competition by lowering entry barriers and increasing transmission access.” The Electric Energy Market Competition Task Force, Report to Congress on Competition in Wholesale and Retail Markets for Electric Energy , at 2, available at http://www.ferc.gov/legal/fed-sta/ene-polact/epact-final-rpt.pdf (last visited Mar. 20, 2015). 71 The Electric Energy Market Competition Task Force, Report to Congress on Competition in Wholesale and Retail Markets for Electric Energy , at 2, available athttp://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-finalrpt.pdf (last visited Mar. 20, 2015). 72 These entities are also referred to as merchant generators.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 122 of 1275 producing approximately 37 percent of net generation in 2013. 73 Electric utilities in some states remain vertically integrated without retail competition from IPPs. Today, there are over 3,000 public, private, and cooperative utilities in the United

States. 74 These utilities include both investor-owned utilities 75

and consumer-owned utilities. 76 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. 77 These larger transmission

73 Energy Information Administration, Electric Power Annual , Table 1.1 Total Electric Power Summary Statistics , 2013 and 2012 (2015), available at http://www.eia.gov/electricity/annual/html/epa_01_01.html. 74 Regulatory Assistance Project (RAP), Electricity Regulation in the US: A Guide , at 9 (2011), available at http://www.raponline.org/document/download/id/645. 75 Investor-owned utilities are private companies that are financed by a combination of shareholder equity and bondholder debt. Regulatory Assistance Project (RAP), Electricity Regulation in the US: A Guide , at 9 (2011), available at http://www.raponline.org/document/download/id/645. 76 Consumer-owned utilities include municipal utilities, public utility districts, cooperatives, and a variety of other entities such as irrigation districts. Regulatory Assistance Project (RAP), Electricity Regulation in the US: A Guide , at 9-10 (2011), available at http://www.raponline.org/document/download/id/645. 77 Peter Fox-Penner, Electric Utility Restructuring: A Guide to the Competitive Era , Public Utility Reports, Inc., at 5, 34 (1997). “The extent of the power system’s short-run physical interdependence is remarkable, if not entirely unique. No other large, multi-stage industry is required to keep every single producer in a region – whether or not owned by the same company*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 123 of 1275 lines are able to access generation that is located more remotely, with transmission lines crossing many miles, including

state borders. 78 Closer to end users, electricity is transformed into a lower voltage that is transported across localized

transmission lines to homes and businesses. 79 Localized transmission lines make up the distribution system. These three components of the electricity system - generation, transmission,

– in immediate synchronization with all other producers.” Id. at 34. “At an early date, those providing electric power recognized that peak use for one system often occurred at a different time from peak use in other systems. They also recognized that equipment failures occurred at different times in various systems. Analyses showed significant economic benefits from interconnecting systems to provide mutual assistance; the investment required for generating capacity could be reduced and reliability could be improved. This lead [sic] to the development of local, then regional, and subsequently three transmission grids that covered the United States and parts of Canada.” Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 5-6 (2d ed. 2010). 78 Burn, An Energy Journal, The Electricity Grid: A History , available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). Because of the ease and low cost of converting voltages in an alternating current (AC) system from one level to another, the bulk power system is predominantly an AC system rather than a direct current (DC) system. In an AC system, electricity cannot be controlled like a gas or liquid by utilizing a valve in a pipe. Instead, absent the presence of expensive control devices, electricity flows freely along all available paths, according to the laws of physics. U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations , at 6 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 79 Peter Fox-Penner, Electric Utility Restructuring: A Guide to the Competitive Era , Public Utility Reports, Inc., at 5 (1997).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 124 of 1275 and distribution - are closely related and must work in coordination 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. Facilities planned and constructed in one segment can impact facilities and operations in other segments and vice

versa. The North American electric grid has developed into a large, interconnected system. 80 Electricity from a diverse set of generation resources such as natural gas, nuclear, coal, and renewables is distributed over high-voltage transmission lines

divided across the continental United States into three synchronous interconnections – the Eastern Interconnection, Western Interconnection, and the Texas Interconnection. 81 These

80 U .S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations , at 5 (Apr. 2004), available athttp://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 81 Regulatory Assistance Project (RAP), Electricity Regulation in the US: A Guide , 2011, at 1, available at http://www.raponline.org/document/download/id/645.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 125 of 1275 three synchronous systems each act like a single machine. 82 Diverse resources generate electricity that is transmitted and distributed through a complex system of interconnected components to industrial, business, and residential consumers. Unlike other industries where sources make operational decisions independently, the utility power sector is unique in that electricity system resources operate in a complex, interconnected grid system that is physically interconnected and operated on an integrated basis across large regions. Additionally, a federal, state, and local regulatory network oversees policies and practices that are applied to how the system is designed and operates. In this interconnected system, system operators must ensure that the amount of electricity available is precisely matched with the amount needed in real time. System operators have a number of resources potentially available to meet electricity demand, including electricity generated by electric generation units such as coal, nuclear, renewables, and natural gas, as well as demand-side resources 83 ,

82 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 159 (2d ed. 2010). 83 “Measures using demand-side resources comprise actions taken on the customer’s side of the meter to change the amount and/or timing of electricity use in ways that will provide benefits to the electricity supply system.” David Crossley, Regulatory Assistance Project (RAP), Effective Mechanisms to Increase the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 126 of 1275 such as energy efficiency 84 and demand response. 85 Generation, outages, and transmission changes in one part of the synchronous grid can affect the entire interconnected grid. 86 The interconnection is such that “[i]f a generator is lost in New York City, its affect is felt in Georgia, Florida, Minneapolis, St. Louis, and New Orleans.” 87 The U.S. Supreme Court has similarly recognized the interconnected nature of the electricity grid. 88

Use of Demand-Side Resources , at 9 (2013), available at www.raponline.org. 84 Energy efficiency is using less energy to provide the same or greater level of service. Demand-side energy efficiency refers to an extensive array of technologies, practices and measures that are applied throughout all sectors of the economy to reduce energy demand while providing the same, and sometimes better, level and quality of service. 85 Demand response involves “[c]hanges in electric usage by demand-side resources from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.” Federal Energy Regulatory Commission, Reports on Demand Response & Advanced Metering , (Dec. 23, 2014), available at http://www.ferc.gov/industries/electric/indusact/demand-response/dem-res-adv-metering.asp. 86 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 159 (2d ed. 2010). 87 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 160 (2d ed. 2010). 88

Federal Power Comm’n v. Florida Power & Light Co. , 404 U.S. 453, at 460 (1972) (quoting a Federal Power Commission hearing examiner, "`If a housewife in Atlanta on the Georgia system turns on a light, every generator on Florida’s system almost instantly is caused to produce some quantity of additional electric energy which serves to maintain the balance in the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 127 of 1275 Today, federal, state, and local entities regulate electricity providers. 89 Overlaid on the physical electricity network is a regulatory network that has developed over the last century or more. This regulatory network “plays a vital role in the functioning of all other networks, sometimes providing specific rules for functioning while at other times providing restraints within which their operation must be conducted.” 90 This unique regulatory network results in an electricity grid that is both physically interconnected and connected through a network of regulation on the local, state, and federal levels. This regulation seeks to reconcile the fact that electricity is a public good with the fact that facilities providing that

interconnected system between generation and load.’”) (citation omitted). See also New York v. FERC , 535 U.S. 1, at 7 (2002) (stating that “any electricity that enters the grid immediately becomes a part of a vast pool of energy that is constantly moving in interstate commerce.”) (citation omitted). In Federal Power Comm’n v. Southern California Edison Co. , 376 U.S. 205 (1964), the Supreme Court found that a sale for resale of electricity from Southern California Edison to the City of Colton, which took place solely in California, was under Federal Power Commission jurisdiction because some of the electricity that Southern California Edison marketed came from out of state. The Supreme Court stated that, “`federal jurisdiction was to follow the flow of electric energy, an engineering and scientific, rather than a legalistic or governmental, test.’” Id. at 210 (quoting Connecticut Light & Power Co. v. Federal Power Commission , 324 U.S. 515, 529 (1945) (emphasis omitted)). 89 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 214 (2d ed. 2010). 90 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 213 (2d ed. 2010).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 128 of 1275 electricity are privately owned. 91 While this regulation began on the state and local levels, federal regulation of the electricity system increased over time. With the passage of the EPAct 1992 and the EPAct 2005, the federal government’s role in electricity regulation greatly increased. 92 “The role of the regulator now includes support for the development of open and fair wholesale electric markets, ensuring equal access to the transmission system and more hands-on oversight and control of the planning and operating rules for the industry.” 93

2. Electric system dispatch System operators typically dispatch the electric system through a process known as economic dispatch. Economic dispatch has been defined as “the operation of generation facilities to produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits of generation and

transmission facilities.” 94 Electricity demand varies across geography and time in response to numerous conditions, such that electric generators are constantly responding to changes in the

91 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 213 (2d ed. 2010). 92 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 214 (2d ed. 2010). 93 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 214 (2d ed. 2010). 94 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005), section 1234(b).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 129 of 1275 most reliable and cost-effective manner possible. The cost of operating electric generation varies based on a number of factors, such as fuel and generator efficiency. 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. 95 Renewables, hydroelectric, and nuclear have little to no variable costs. In an economic dispatch system, units with higher variable costs, such as fossil fuel-fired generators, generally are the first generation to be displaced by lower variable cost generation, like RE.In states with cost-of-service regulation of verticallyintegrated 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 are generally responsible for dispatch in non-vertically integrated states. They coordinate, control, and monitor

95 Variable costs also include costs associated with operation and maintenance and costs of operating a pollution control and/or emission allowance charges.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 130 of 1275 electricity transmission systems to ensure cost-effective and reliable delivery of power, and they are independent from market participants.

3. Reliability considerations 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. 96 In 1965, the northeastern U.S. and southeastern Ontario, Canada experienced the largest power blackout to date, impacting 30 million people. 97 In response to the 1965 blackout and a Federal Power Commission recommendation, 98 industry developed the National Electric Reliability Council (NERC) and nine reliability councils. The organization later became known

96 North American Electric Reliability Corporation, History of NERC , at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 97 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 39 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 98 The Federal Power Commission, a precursor to FERC, recommended “the formation of a council on power coordination made up of representatives from each of the nation’s regional coordinating organizations, to exchange and disseminate information and to review, discuss and assist in resolving interregional coordination matters.” North American Electric Reliability Corporation, History of NERC , at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 131 of 1275 as the North American Electric Reliability Council to recognize Canada’s participation. 99 In August 2003, North America experienced its worst blackout to date creating an outage in the Midwest, Northeast, and Ontario, Canada. 100 This blackout was massive in scale impacting an area with an estimated 50 million people and 61,800 megawatts of electric load. 101 The U.S. and Canada formed a joint task force to investigate the causes of the blackout and made recommendations to avoid similar outages in the future. One of the task force’s major recommendations was that the U.S. Congress should pass legislation making electric reliability standards mandatory and enforceable. 102

99 North American Electric Reliability Corporation, History of NERC , at 2 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf . The North American Electric Reliability Council became the North American Electric Reliability Corporation in 2007. Id. at 4. 100 North American Electric Reliability Corporation, History of NERC , at 3 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 101 U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations , at 1 (Apr. 2004), available athttp://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. The outage impacted areas within Ohio, Michigan, Pennsylvania, New York, Vermont, Massachusetts, Connecticut, New Jersey, and the Canadian province of Ontario. Id. 102 U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations , at 2 (Apr. 2004), available at*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 132 of 1275 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. 103 In 2006, the Federal Energy Regulatory Commission (FERC) certified NERC as the ERO. 104 “NERC develops and enforces Reliability Standards; monitors the Bulk-Power System; assesses adequacy annually via a 10-year forecast and winter and summer forecasts; audits owners, operators and users for preparedness; and educates and trains industry personnel.” 105

http://www.ferc.gov/industries/electric/indusact/ reliability/blackout/ch1-3.pdf. 103 Mandatory Reliability Standards for the Bulk-Power System , Order No. 693, 118 FERC ¶ 61,218, at P 3 (2007) (citing 16 U.S.C. 824o(e)(3)). 104 Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards , Order No. 672, 114 FERC ¶ 61,104 (2006). 105 North American Electric Reliability Corporation, Frequently Asked Questions , at 2 (Aug. 2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 133 of 1275 The United States, Canada, and part of Mexico are divided up into eight reliability regional entities. 106 These regional entities include Florida Reliability Coordinating Council (FRCC), Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), Reliability First Corporation (RFC), SERC Reliability Corporation (SERC), Southwest Power Pool, RE (SPP), Texas Reliability Entity (TRE), and Western Electricity Coordinating Council (WECC). 107 Regional entity members come from all segments of the electric industry. 108 NERC delegates authority, with FERC approval, to these regional entities to enforce reliability standards, both national andregional reliability standards, and engage in other standardsrelated duties delegated to them by NERC. 109 NERC ensures that

106 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 49-50 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 107 Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics , at 50 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 108 North American Electric Reliability Corporation, Key Players , available at http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx (last visited Mar. 12, 2015). “The members of the regional entities come from all segments of the electric industry: investor-owned utilities; federal power agencies; rural electric cooperatives; state, municipal and provincial utilities; independent power producers; power marketers; and end-use customers.” Id. 109 North American Electric Reliability Corporation, Frequently Asked Questions , at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 134 of 1275 there is a consistency of application of delegated functions with appropriate regional flexibility. 110 NERC divides the country into assessment areas and annually analyzes the reliability, adequacy, and associated risks that may affect the upcoming summer, winter, and long-term, 10-year period. Multiple other entities such as FERC, the Department of Energy, state public utility commissions, ISOs/RTOs 111 , and other planning

For example, a regional entity may propose reliability standards, including regional variances or regional reliability standards required to maintain and enhance electric service reliability, adequacy, and security in the region. See, e.g., Amended and Restated Delegation Agreement Between North American Reliability Corporation and Midwest Reliability Organization , Bylaws of the Midwest Reliability Organization, Inc. , Section 2.2 (2012), available at http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agr eements%20DL/MRO_RDA_Effective_20130612.pdf. 110 North American Electric Reliability Corporation, Frequently Asked Questions , at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 111 ISOs/RTOs plan for system needs by “effectively managing the load forecasting, transmission planning, and system and resource planning functions.” For example, the New York Independent System Operator (NYISO) conducts reliability planning studies, which “are used to assess current reliability needs based on user trends and historical energy use.” NYISO, Planning Studies , available at http://www.nyiso.com/public/markets_operations/services/planning /planning_studies/index.jsp. See also PJM, Reliability Assessments , available at https://www.pjm.com/planning/rtepdevelopment/reliability-assessments.aspx (stating that the PJM “Regional Transmission Expansion Planning (RTEP) process includes the development of periodic reliability assessments to address specific system reliability issues in addition to the ongoing expansion planning process for the interconnection process of generation and merchant transmission.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 135 of 1275 authorities also consider the reliability of the electric system. There are numerous remedies that can be utilized to solve a potential reliability problem, including long-term planning, transmission system upgrades, installation of new generating capacity, demand response, and other demand side

actions.

4. Modern electric system trends 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., with smaller amounts provided by other types of generation including nuclear, and renewables such as wind, solar, and hydroelectric power. Coal provided the largest percentage of the fossil fuel generation. 112 In recent years, the nation has seen a sizeable increase in renewable generation such as wind and solar, as well as a shift from coal to natural

gas. 113 In 2013, fossil fuels supplied 67 percent of U.S.

112 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Sector” data from Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015). 113 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Sector” data from Monthly Energy Review May 2015, release data April 25, 2014, available at*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 136 of 1275 electricity, 114 but the amount of renewable generation capacity continued to grow. 115 From 2007 to 2014, use of lower- and zerocarbon energy sources such as wind and solar grew, while other major energy sources such as coal and petroleum generally experienced declines. 116 Renewable electricity generation, including from large hydro-electric projects, grew from 8 percent to 13 percent over that time period. 117 Between 2000 and 2013, approximately 90 percent of new power generation capacity

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015). 114 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Sector” data from Monthly Energy Review May 2015, release data April 25, 2014, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015). 115 Based on Table 6.3 (New Utility Scale Generating Units by Operating Company, Plant, Month, and Year) of the U.S. Energy Information Administration (EIA) Electric Power Monthly, data for December 2013, for the following renewable energy sources: solar, wind, hydro, geothermal, landfill gas, and biomass. Available at: http:// www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_0 3. 116 U.S. Energy Information Administration, “Table 7.2b Electricity Net Generation: Electric Power Sector” data from Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015). 117 Bloomberg New Energy Finance and the Business Council for Sustainable Energy , 2015 Factbook: Sustainable Energy in America , at 16 (2015), available at http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20Am erica%20Factbook.pdf. Bloomberg gave projections for 2014 values, accounting for seasonality, based on latest monthly values from EIA (data available through October 2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 137 of 1275 built in the U.S. came in the form of natural gas or renewable energy facilities. 118 In 2015, the U.S. Energy Information Administration (EIA) projected the need for 28.4 GW of additional base load or intermediate load generation capacity through 2020. 119 The vast majority of this new electric capacity (20.4 GW) is already under development (under construction or in advanced planning), with approximately 0.7 GW of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new NGCC capacity already in development. While the change in the resource mix has accelerated in recent years, 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. For example, the average age of

U.S. coal steam units in 2015 is 45. 120 In its 2013 Report Card

118 Energy Information Administration, Electricity: Form EIA-860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/. 119 EIA, Annual Energy Outlook for 2015 with Projections to 2040 , Final Release , available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEOnumbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects. 120 We calculated the average age of coal steam units based on the NEEDS inventory (a “snapshot” of the sector in 2016), and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 138 of 1275

for America’s Infrastructure , the American Society for Civil Engineers noted that “America relies on an aging electrical grid and pipeline distribution systems, some of which originated in

the 1880s.” 121 While there has been an increased investment in electric transmission infrastructure since 2005, the report also found that “ongoing permitting issues, weather events, and limited maintenance have contributed to an increasing number of failures and power interruptions.” 122 However, innovative technologies have increasingly entered the electric energy space, helping to provide new answers to how to meet the electricity needs of the nation. These new technologies can enable the nation to answer not just questions as to how to reliably meet electricity demand, but also how to meet electricity demand reliably and cost-effectively with the lowest possible emissions and the greatest efficiency. 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

adding back units with actual/planned retirements in 2012-2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx. 121 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/. 122 American Society for Civil Engineers, 2013 Report Card for America’s Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 139 of 1275 net generation increased by approximately 32 percent between

2005 and 2014. 123 In 2014, natural gas accounted for approximately 27 percent of net generation. 124 EIA projects that this demand growth will continue with its Annual Energy Outlook

2015 (AEO 2015) Reference case forecasting that natural gas will produce 31 percent of U.S. electric generation in 2040. 125 Renewable sources of electric generation also have a history of meeting electricity demand in the United States 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

123 U.S. Energy Information Administration (EIA), Electric Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All Sectors), 2005-February 2015 (2015), available at http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e pmt_1_1 (last visited May 26, 2015). 124 Id. 125 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2015 with Projections to 2040 , at 24-25 (2015), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. According to the EIA, the reference case assumes, “Real gross domestic product (GDP) grows at an average annual rate of 2.4% from 2013 to 2040, under the assumption that current laws and regulations remain generally unchanged throughout the projection period. North Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 dollars) in 2040.” Id. at 1. The EIA provides complete projection tables for the reference case in Appendix A of its report.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 140 of 1275 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). 126 QFs were either cogeneration

facilities 127 or small generation resources that use renewables such as wind, solar, biomass, geothermal, or hydroelectric power as their primary fuels. 128 Through PURPA, Congress supported the development of more renewable energy generation in the U.S. States have also taken a significant lead in requiring the development of renewable resources. In particular, a number of states have adopted renewable portfolio standards (RPS). As of 2013, 29 states and the District of Columbia have enforceable

RPS or similar laws. 129 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.

126 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 127 Cogeneration facilities utilize a single source of fuel to produce both electricity and another form of energy such as heat or steam. Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 128 Casazza, J. and Delea, F., Understanding Electric Power Systems , IEEE Press, at 220-221 (2d ed. 2010). 129 U.S. Energy Information Administration (EIA), Annual Energy Outlook 2014 with Projections to 2040 , at LR-5 (2014), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf (last visited May 26, 2015).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 141 of 1275 electricity. 130 Total non-hydro RE capacity was approximately 13,000 megawatts (MW) in 1998. In 2013, total capacity was over five times higher with 80,000 MW of non-hydro RE capacity. 131 In particular, there has been substantial growth in the wind and photovoltaic (PV) markets in the past decade. Since 2009, wind energy has tripled and solar capacity has grown twenty-fold. 132 The market for RE is projected to grow to $460 billion per year by 2030. RE growth is further encouraged by the significant amount of existing natural resources that can support RE production (solar, water, wind, and geothermal) in the United States. In the Energy Information Administration’s Annual Energy Outlook 2015, RE generation grows substantially from 2013 to

2040 in the reference case and all alternative cases. 133 In the reference case, RE generation increases by more than 70 percent

from 2013 to 2040 and accounts for over one-third of new

130 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at ES-6 (2014). 131 Barbose, G., Renewables Portfolio Standards in the United States: A Status Update , Presentation at State-Federal RPS Collaborative National Summit on RPS (2013), available at http://emp.lbl.gov/sites/all/files/rps_summit_nov_2013.pdf (last visited May 27, 2015). 132 Energy Information Administration, Monthly Energy Review, May 2015, Table 7.2b, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 133 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at 25 (2014), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 142 of 1275 generation capacity. 134 Rapid growth in RE generation is projected to continue as costs of RE generation fall relative to the costs of other generation technologies. 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. 135 This trend continued in the early 1990s. Energy efficiency has been utilized to meet energy demand to varying levels since that time. As of April 2014, 25

states 136 have “enacted long-term (3+ years), binding energy

134 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at ES-6 (2015), available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last visited May 27, 2015). 135 Edison Electric Institute, Making a Business of Energy Efficiency: Sustainable Business Models for Utilities , at 1 (2007), available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation /Documents/Making_Business_Energy_Efficiency.pdf. Congress passed legislation in the 1970s that jumpstarted energy efficiency in the U.S. For example, President Ford signed the Energy Policy and Conservation Act (EPCA) of 1975 – the first law on the issue. EPCA authorized the Federal Energy Administration (FEA) to “develop energy conservation contingency plans, established vehicle fuel economy standards, and authorized the creation of efficiency standards for major household appliances.” Alliance to Save Energy, History of Energy Efficiency , at 6 (2013) (citing Anders, “The Federal Energy Administration,” 5; Energy Policy and Conservation Act, S. 622, 94th Cong. (1975-1976)), available at https://www.ase.org/sites/ase.org/files/resources/Media%20browse r/ee_commission_history_report_2-1-13.pdf. 136 American Council for an Energy-Efficient Economy, State Energy Efficiency Resource Standards (EERS) (2014), available at http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE did not include Indiana (EERS eliminated), Delaware (EERS*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 143 of 1275 savings targets, or energy efficiency resource standards (EERS).” 137 Funding for energy efficiency programs has grown rapidly in recent years, with budgets for electric efficiency programs totaling $5.9 billion in 2012. 138 Advancements and innovation in power sector technologies provide the opportunity to address CO 2 emission levels at affected power plants while at the same time improving the overall power system in the U.S. by lowering the carbon intensity of power generation, and ensuring a reliable supply of power at a reasonable cost. D. Congress’ Awareness of Climatic Change 139 As early as 1970, Congress learned that ongoing pollution, including from manmade carbon dioxide, could “threaten irreversible atmospheric and climatic changes.” 140 Likewise,

pending), Florida (programs funded at levels far below what is necessary to meet targets), Utah, or Virginia (voluntary standards) in its calculation. 137 American Council for an Energy-Efficient Economy, State Energy Efficiency Resource Standards (EERS) (2014), available at http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. 138 American Council for an Energy-Efficient Economy, The 2013 State Energy Efficiency Scorecard , at 17 (Nov. 2013), available at http://aceee.org/sites/default/files/publications/researchreport s/e13k.pdf.

139 The following discussion is not meant to be exhaustive; indeed, there are many other instances, including outside the context of the CAA, where Congress discussed climate change.

140 Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 349.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 144 of 1275 President Nixon’s Council on Environmental Quality (CEQ) reported that “the addition of particulates and carbon dioxide in the atmosphere could have dramatic and long-term effects on

world climate.” 141 In fact, the CEQ’s First Annual Report, which was transmitted to Congress, devoted an entire chapter to “Man’s

Inadvertent Modification of Weather and Climate.” 142 Moreover, Charles Johnson, Jr., Administrator of the Consumer Protection

and Environmental Health Service even testified before the House

Subcommittee on Public Health that “the carbon dioxide balance might result in the heating up of the atmosphere whereas the reduction of the radiant energy through particulate matter released to the atmosphere might cause reduction in radiation

that reaches the earth.” 143 Administrator Johnson explained that

the Nixon Administration was “concerned ... that neither of these

141 Council on Environmental Quality, “The First Annual Report of the Council on Environmental Quality,” p. 110 (Aug. 1970) (recognizing also that “[man] can increase the carbon dioxide content of the atmosphere by burning fossil fuels” and postulating that an increase in the earth’s average temperature by about 2o to 3o F “could in a period of decades, lead to the start of substantial melting of ice caps and flooding of coastal regions.”).

142 Council on Environmental Quality, “The First Annual Report of the Council on Environmental Quality,” p. 93-104 (Aug. 1970)

143 Testimony of Charles Johnson, Jr., Administrator of the Consumer Protection and Environmental Health Service (Administration Testimony), Hearing of the House Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 145 of 1275 things happen” and that they were “watching carefully the kind of prognosis, the kind of calculations that the scientists make to look at the continuous balance between heat and cooling of the total earth’s atmosphere.” 144 He concluded that “[w]hat we are trying to do, however, in terms of our air pollution effort should have a very salutary effect on either of these.” 145 Climatic effects continued to gain Congressional attention by the 1977 CAA Amendments. However, scientific studies remained inconclusive as to warming or cooling trends. 146 In deference to

144 Testimony of Charles Johnson, Jr., Administrator of the Consumer Protection and Environmental Health Service (Administration Testimony), Hearing of the House Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.

145 Testimony of Charles Johnson, Jr., Administrator of the Consumer Protection and Environmental Health Service (Administration Testimony), Hearing of the House Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.

146 For instance, while scientists, such as Stephen Schneider of the National Center for Atmospheric Research, testified that “manmade pollutants will affect the climate,” they believed that we would “see a general cooling of the Earth’s atmosphere.” Rep. Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA Legis. Hist. at 6477. Additionally, the Department of Transportation’s climatic impact assessment program and the Climatic Impact Committee of the National Research Council, National Academies of Science and Engineering both reported that “warming or cooling” could occur. Id. at 6476. See also Sen. Bumpers, Sen. Debates on S. 3219 (August 3, 1976), 1977 CAA Legis. Hist. at 5368 (inserting “Summary of Statements Received [in the Subcommittee on the Environment and the Atmosphere] from Professional Societies for the Hearings on Effects of Chronic Pollution” into the record, which noted that “there is near*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 146 of 1275 that uncertainty, and as part of the 1977 CAA Amendments, Congress ordered the National Oceanic and Atmospheric Administration to research and monitor the stratosphere “for the purpose of early detection of changes in the stratosphere and climatic effects of such changes.” 147 Finally, in the 1990 CAA Amendments, Congress specifically required the EPA to collect data on carbon dioxide emissions from all sources subject to the newly enacted operating permit

program. 148 The provision recognizes that “[s]cientists have disagreed about the scope and magnitude of global climate change from manmade air pollution, and much of that disagreement stems from lack of necessary data to assess the impact these emissions may have on the Earth’s climate.” 149 Accordingly, the provision “helps fill this information gap.” 150 It was designed to “give us a head start if and when we need to take steps to reduce our

carbon dioxide emissions.” 151

unamity [sic] that carbon dioxide concentrations in the atmosphere are increasing rapidly.”).

147 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728. 148 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 149 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 CAA Legis. Hist. at 2612. 150 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 CAA Legis. Hist. at 2612. 151 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 CAA Legis. Hist. at 2613.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 147 of 1275 Congress also recognized that certain tools were particularly helpful in addressing climate change. For instance, the Senate report discussing Title IV noted that “[e]nergy efficiency is a crucial tool for controlling the emissions of carbon dioxide, the gas chiefly responsible for the intensification of the atmospheric ‘greenhouse effect.’” 152 Similarly, “renewables not only significantly curtail sulfur dioxide emissions, but they emit little or no nitrogen oxides

and carbon dioxide”. 153 E. International Agreements and Actions In this final rule, the United States is taking action to limit GHGs from one of its largest emission sources. Climate change is a global problem, and the United States is not alone in taking action to address it. The United Nations Framework Convention on Climate Change (UNFCCC) 154 is the international treaty under which countries (called “Parties”) cooperatively consider what can be done to limit anthropogenic climate change 155 and adapt to climate change impacts. Currently, there

152 Sen. Chaffe, Sen. Debate on S. 1630 (Jan. 24, 1990), 1990 CAA Legis. Hist. at 8662.

153 Additional Views of Rep. Markey and Rep. Moorhead, H.R. Rep. No. 101-490, at 674 (May 17, 1990). 154 http://unfccc.int/2860.php 155 Article 2, Objective, The ultimate objective of this Convention and any related legal instruments that the Conference of the Parties may adopt is to achieve, in accordance with the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 148 of 1275 are 195 Parties to the UNFCCC, including the United States. The Conference of the Parties (COP) meets annually and is currently considering commitments countries can make to limit emissions after 2020. The 2015 COP will be in Paris, and countries will announce their post-2020 commitments there or beforehand. In April 2015, the United States announced its commitment to reduce GHG emissions 26-28% below 2005 levels by 2025. 156 As Parties to both the UNFCCC and the Kyoto Protocol 157 , the European Union (EU) and member countries have taken aggressive

action to reduce GHG emissions. 158 EU initiatives to reduce greenhouse gas emissions include the EU Emissions Trading System, legislation to increase the adoption of renewable energy sources, strengthened energy efficiency targets, vehicle

relevant provisions of the Convention, stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. Such a level should be achieved within a time frame sufficient to allow ecosystems to adapt naturally to climate change, to ensure that food production is not threatened and to enable economic development to proceed in a sustainable manner. http://unfccc.int/files/essential_background/convention/backgrou nd/application/pdf/convention_text_with_annexes_english_for_post ing.pdf 156 United States Cover Note to Intended Nationally Determined Contribution (INDC). Available online at: http://www4.unfccc.int/submissions/INDC/Published%20Documents/Un ited%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and% 20Accompanying%20Information.pdf 157 http://unfccc.int/kyoto_protocol/items/2830.php 158 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 149 of 1275 emission standards, and support for the development of CCS technology for use by the power sector and other industrial sources. In 2009, the EU announced its “20-20-20 targets,” including a 20% reduction in GHG emissions from 1990 levels by 2020, an increase of 20% in the share of energy consumption produced by renewable resources, and a 20% improvement in energy efficiency. In March 2015, the EU announced its commitment to reduce domestic GHG emissions by at least 40% from 1990 levels by 2030. 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% of its emissions of greenhouse gases 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 2 emissions more than any other country through a historic effort to slow forest loss. The*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 150 of 1275 deforestation rate in Brazil in 2014 was roughly 75% below the average for 1996 to 2005. 159

This final rule demonstrates to other countries that the United States 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. F. Statutory and Regulatory Requirements 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.” 160 The EPA has listed more than 60 stationary source categories under this provision. 161 Once the EPA lists a source category, the EPA must, under CAA section 111(b)(1)(B), establish “standards of performance” for emissions

159 http://www.nature.com/news/stopping-deforestation-battle-forthe-amazon-1.17223 160 CAA §111(b)(1)(A). 161 See 40 CFR 60 subparts Cb – OOOO.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 151 of 1275 of air pollutants from new sources in the source categories. 162 These standards are known as new source performance standards (NSPS), and they are national requirements that apply directly to the sources subject to them.

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 hazardous air pollutants (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.”

162 CAA §111(b)(1)(B), 111(a)(1).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 152 of 1275 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.” 163 If a state does not submit a plan, or if the EPA does not approve a state’s plan, then the EPA must establish a plan for that state. 164 Once a state receives the EPA’s approval of its plan, the provisions in the plan become federally enforceable against the entity responsible for noncompliance, in the same manner as the provisions of an approved SIP under the Act. 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 § 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 “all non-Federal

163 CAA section 111(d)(2)(A). 164 CAA section 111(d)(2)(A).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 153 of 1275 authorities, including local agencies, interstate associations, and State-wide programs that have been delegated authority to implement: (1) the provisions of this part and/or (2) the permit program established under part 70 of this chapter. The term State shall have its conventional meaning where clear from the

context.” The EPA believes that the last sentence refers to the conventional meaning of “state” under the CAA. Thus, the EPA believes the term “state” as used in the emission guidelines is most reasonably interpreted as including the meaning ascribed to that term in section 302(d) of the CAA, which expressly includes

U.S. territories. 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 Federal Register 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 154 of 1275 in its area of Indian country 165 will have the opportunity, but not the obligation, to apply for eligibility to develop and implement a CAA section 111(d) plan. The Indian tribe would need to be approved by the EPA as eligible to develop and implement a CAA section 111(d) plan following the procedure set forth in 40 CFR part 49. Once a tribe is approved as eligible for that purpose, it would be treated in the same manner as a state, and references in the emission guidelines to states would refer equally to the tribe. The EPA notes that, while tribes have the opportunity to apply for eligibility to administer CAA programs, they are not required to do so. Further, the EPA has established procedures in 40 CFR part 49 (see particularly 40 CFR 49.7(c)) that permit eligible tribes to request approval of reasonably severable partial program elements. Those procedures are applicable here. Although the EPA believes the current emission guidelines are sufficiently inclusive, the EPA is amending the applicability provision of the emission guidelines slightly to avoid any doubt that the guidelines apply to U.S. territories

165 The EPA is aware of at least four affected sources located in Indian Country: two on Navajo lands – the Navajo Generating Station and the Four Corners Generating Station; one on Ute lands – the Bonanza Generating Station; and one on Fort Mojave lands, the South Point Energy Center. The affected EGUs at the first three plants are coal-fired EGUs. The fourth affected EGU is an NGCC facility.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 155 of 1275 with affected EGUs and to any Indian tribe that has been approved by the EPA as eligible to develop and implement a plan. 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, 166 and has revised them in the years since. 167 (We refer to the regulations generally as the implementing regulations.) These regulations provide that, in promulgating requirements for sources under CAA section 111(d), the EPA first develops regulations known as “emission guidelines,” which establish binding requirements that states must address when they develop their plans. 168 The implementing regulations also establish

timetables for state and EPA action: states must submit state

166 “State Plans for the Control of Certain Pollutants from Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 167 The most recent amendment was in 77 Fed. Reg. 9304 (Feb. 16, 2012). 168 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that it used the term “emissions guidelines” – instead of emissions limitations – to make clear that guidelines would not be binding requirements applicable to the sources, but instead are “criteria for judging the adequacy of State plans.” 40 Fed. Reg. at 53,343.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 156 of 1275 plans within 9 months of the EPA’s issuance of the guidelines, 169 and the EPA must take final action on the state plans within 4 months of the due date for those plans, 170 although the EPA has authority to extend those deadlines. 171 In this rulemaking, the EPA is following the requirements of the implementing regulations, and is not re-opening them, except that the EPA is extending the timetables, as described below. Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (i.e., sulfuric acid plants (acid mist), phosphate fertilizer plants (fluorides), primary aluminum plants (fluorides), Kraft pulp plants (total reduced sulfur), and municipal solid waste landfills (landfill gases)). 172 In addition, the agency has regulated additional pollutants under CAA section 111(d) in

169 40 CFR 60.23(a)(1). 170 40 CFR 60.27(b). 171 See 40 CFR 60.27(a). 172 See “Phosphate Fertilizer Plants; Final Guideline Document Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of Performance for New Stationary Sources; Emission Guideline for Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft Pulp Mills, Notice of Availability of Final Guideline Document,” 44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 (Apr. 17, 1980); “Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 (Mar. 12, 1996).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 157 of 1275 conjunction with CAA section 129. 173 The agency has not previously regulated CO 2 or any other greenhouse gas under CAA section 111(d). 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 2 emissions. Doing so results in a broader, forward-thinking approach to the design of programs to yield critical CO 2 reductions that improve the overall power system by lowering the carbon intensity of power generation, while offering continued reliability and cost-effectiveness.

173 See, e.g., “Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Sewage Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15,372 (Mar. 21, 2011).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 158 of 1275 These opportunities exist in the utility power sector in ways

that were not relevant or available for other industries for which the EPA has established CAA section 111(d) emission guidelines. 174 In this action, the EPA is promulgating emission guidelines for states, U.S. territories, and tribes to follow in developing their CAA section 111(d) plans to reduce emissions of CO 2 from the utility power sector. G. Legislative and Regulatory Background for CAA Section 111 In the final days of December 1970, Congress enacted sweeping changes to the Air Quality Act of 1967 to confront an

“environmental crisis.” 175 The Air Quality Act—which expanded federal air pollution control efforts after the enactment of the Clean Air Act of 1963—prioritized the adoption of ambient air standards but failed to target stationary sources of air

174 See “Phosphate Fertilizer Plants; Final Guideline Document Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of Performance for New Stationary Sources; Emission Guideline for Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft Pulp Mills, Notice of Availability of Final Guideline Document,” 44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 (Apr. 17, 1980); “Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 (Mar. 12, 1996).

175 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 224.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 159 of 1275 pollution. As a result, “[c]ities up and down the east coast were living under clouds of smoke and daily air pollution

alerts.” 176 In fact, “[o]ver 200 million tons of contaminants ... spilled into the air” each year. 177 The 1970 CAA Amendments were designed to face this crisis “with urgency and in candor.” 178 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”. 179 Under these provisions,

176 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123.

177 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 224. These pollutants fell into five main classes of pollutants: carbon monoxide, particulates, sulfur oxides, hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. at 244.

178 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123.

179 “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 Stat. 1676, 1678 (Dec. 31, 1970). The “adverse effect” criterion was later amended to refer to pollutants “which may reasonably be anticipated to endanger public health or welfare”. See 42*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 160 of 1275 states would have the primary responsibility for assuring air quality within their entire geographic area but would submit plans to the Administrator for “implementation, maintenance, and enforcement” of national ambient air quality standards. These plans would include “emission limitations, schedules, and timetables for compliance ... and such other measures as may be necessary to insure attainment and maintenance” of the national ambient air quality standards. 180 The second prong—CAA section 111—addressed pollutants on a source category-wide basis. For new sources in a listed source category, CAA section 111(b) established “standards of performance” for pollutants which “cause[] or contribute to the endangerment of public health or welfare.” 181 For existing sources in a listed source category, CAA section 111(d) set out procedures for the establishment of federally enforceable “emission standards” of any pollutant not otherwise controlled under the CAA’s SIP provisions or CAA section 112. 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

U.S.C. § 7408(a)(1)(A). Similar language is also used under the current CAA section 111. See 42 U.S.C. § 7411(b)(1)(A).

180 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680.

181 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 161 of 1275 to protect the public health”. 182 All new or modified sources of any hazardous air pollutant would be required to meet these emission standards. Existing sources were required to meet the same standards or would be shut down unless they obtained a temporary EPA waiver or Presidential exemption. 183 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. 184 That said, states, including Texas and New Jersey, levied “substantial criticisms” against the EPA for not moving rapidly enough. 185 Accordingly, the 1977 CAA Amendments were designed to “provide a greater role for the [s]tates in standards setting under the [CAA],” “protect [s]tates from ‘environmental blackmail’ as they attempt to regulate mobile and competitive industries,” and lastly “provide a check on the

Administrator’s inaction or failure to control emissions adequately.” 186 At bottom, CAA section 111 rests on the definition of a standard of performance under CAA section 111(a)(1), which reads

182 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685.

183 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685.

184 H.R. Rep. No. 95-294, at 194 (May 12, 1977).

185 H.R. Rep. No. 95-294, at 194 (May 12, 1977).

186 H.R. Rep. No. 95-294, at 195 (May 12, 1977).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 162 of 1275 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 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. 187 Despite significant changes to this definition in 1977, Congress reversed course in 1990 and largely reinstated the original

definition. 188 As presently defined, the term applies to the regulation of new and existing sources under CAA sections 111(b) and (d). 189

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

187 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683.

188 “Clean Air Act Amendments of 1990,” Pub. L. 101-549, § 403, 104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the obligation to account for “any nonair quality health and environmental impact and energy requirements” that was added in 1977). 189 As CAA section 111(d) was originally adopted, state plans would have established “emission standards” instead of “standards of performance.” This distinction was later abandoned in 1977 and the same term is used in both CAA sections 111(b) and (d).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 163 of 1275 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”. 190 The House also proposed to prohibit the construction or operation of new sources of “extremely hazardous” pollutants. 191 The Senate bill, on the other hand, authorized “Federal standards of performance,” which would “reflect the greatest degree of emission control which the Secretary [later, the Administrator] determines to be achievable through application of the latest available control technology, processes, operating methods, or other alternatives.” 192 The

190 H.R. 17255, 91st Cong. § 5 (1970).

191 H.R. 17255, 91st Cong. § 5 (1970).

192 S. 4358, 91st Cong. § 6 (1970) (emphasis added). The breadth of the Senate bill is further emphasized in the conference report, which explains that a standard of performance “refers to the degree of emission control which can be achieved through process changes, operation changes, direct emission control, or other methods” and also includes “other means of preventing or controlling air pollution.” S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 164 of 1275

Senate also would have authorized “national emission standards” for hazardous air pollution and other “selected air pollution agents.” 193 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 merged 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). 194 Section 114 of

the Senate bill established emission standards for “selected air pollution agents,” and was intended to bridge the gap between criteria pollutants and hazardous air pollutants. As proposed, the Senate identified fourteen substances for regulation under section 114 and only four substances for regulation under Senate bill 4358, section 115, the predecessor of CAA section 112. 195

193 S. 4358, 91st Cong. § 6 (1970).

194 The House bill did not provide for the direct regulation of existing sources.

195 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 165 of 1275 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.” 196 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. 197 That said, under the newly enacted “ambient air quality and emission standards” sections, Congress directed the EPA to provide states with information “on air pollution control techniques,” including data on “available technology and alternative methods of prevention and control of air pollution” and on “alternative fuels, processes, and operating methods which will result in elimination or significant reduction of emissions.” 198 Similarly, the Administrator would “issue information on pollution control

196 S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing the relationship between sections 114 (addressing emission standards for “selected air pollution agents”) and 115 (addressing hazardous air pollutants) of the Senate bill).

197 See “Clean Air Act Amendments of 1970,” § 12, 84 Stat. at 1706.

198 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 166 of 1275 techniques for air pollutants” in conjunction with establishing emission standards under CAA section 112. However, analogous text is absent from CAA section 111(d). 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. 199 The first category listed was for fossil-fuel fired steam generators, for which EPA proposed and finalized standards for particulate matter, sulfur dioxide, and nitrogen oxides. 200 Several years later, the EPA proposed its implementing regulations for CAA section 111(d). 201 These regulations were finalized in November 1975, and provided for the publication of emission guidelines. 202 The first emissions guidelines were proposed in May 1976 and finalized in March 1977. 203

199 “Standards of Performance for New Stationary Sources: Proposed Standards for Five Categories,” 36 F.R. 15704 (Aug. 17, 1971). See “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684 (requiring the Administrator to publish a list of categories of stationary sources within 90 days of the enactment of the 1970 CAA Amendments).

200 36 F.R. at 15704-706; and “Standards of Performance for New Stationary Sources,” 36 F.R. 24876, 24879 (Dec. 23, 1971).

201 See “State Plans for the Control of Existing Facilities,” 39 F.R. 36102 (Oct. 7, 1974).

202 See “State Plans for the Control of Certain Pollutants from Existing Facilities,” 40 F.R. 53340 (Nov. 17, 1975).

203 See “Phosphate Fertilizer Plants; Draft Guideline Document; Availability,” 41 F.R. 19585(May 12, 1976); and “Phosphate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 167 of 1275 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. 204 Most notably, an increase in coal use as a result of the oil crisis meant that “vigorous and effective control” of air emissions was “even more urgent.” 205 Thus, to curb the projected surge in air emissions, Congress enacted several new provisions to the CAA.

Fertilizer Plants; Final Guideline Document Availability,” 42 F.R. 12022 (Mar. 1, 1977) 204 For example, Congress recognized that many air pollutants had not been regulated despite “mounting evidence” that these pollutants “are associated with serious health hazards”. H.R. Rep. No. 94-1175, 22 (May, 15, 1976). Because EPA “failed to promulgate regulations to institute adequate control measures,” Congress ordered EPA to regulate four specific pollutants that had “been found to be cancer-causing or cancer-promoting”. Id. at 23. This directive, reflected in CAA section 122, specifically added radioactive pollutants, cadmium, arsenic, and polycyclic organic matter “under the various provisions of the Clean Air Act and allows their regulation as criteria pollutants under ambient air quality standards, as hazardous air pollutants, or under new source performance standards, as appropriate.” H.R. Conf. Rep. No. 95-564, 142 (Aug. 3, 1977), 1977 CAA Legis. Hist. at 522. At the same time, Congress made sure that these commands would have no effect on the Administrator’s discretion to address “any substance (whether or not enumerated [under CAA section 122(a))” under CAA sections 108, 112, or 111. 42 U.S.C. § 7422(b).

205 See Statement of EPA Administrator Costle, S. Hearings on S. 272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 30, 1977), 1977 CAA Legis. Hist. at 3532.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 168 of 1275 These new provisions include the prevention of significant deterioration (PSD) program, visibility protections, and requirements for nonattainment areas. 206 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 ( e.g. , work practice or design) standards in limited circumstances, provided states with authority to petition the Administrator for new or revised (and more stringent) standards, and imposed a strict regulatory schedule for establishing standards of performance for categories of major stationary sources that had not yet been

listed. 207 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.’” 208 For fossil-fuel

206 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 127- 129, 91 Stat. 685 (Aug. 7, 1977).

207 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697.

208 H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress separately defined “technological system of continuous emission reduction” as “(A) a technological process for production or operation by any source which is inherently low-polluting or nonpolluting, or (B) technological system for continuous*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 169 of 1275 fired stationary sources, Congress further required a percentage

reduction in emissions from the use of fuels. 209 Together, this was designed to “force new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for use in existing sources where it is

harder to control emissions and where low-sulfur fuel is needed for compliance.” 210 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)”. 211 This was intended to distinguish existing source standards from new source standards, for which “the requirement for [the BSER] has been more narrowly redefined as best technological system of continuous emission

reduction.” 212 Additionally, Congress clarified that states could

reduction of the pollution generated by a source before such pollution is emitted into the ambient air, including precombustion cleaning or treatment of fuels.” “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700; see also 42 U.S.C. § 7411(a)(7).

209 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700.

210 “New Stationary Sources Performance Standards; Electric Utility Steam Generating Units,” 44 F.R. 33580, 33581-82 (June 11, 1979).

211 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 212 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95- 564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 170 of 1275 consider “the remaining useful life” of a source when applying a standard of performance to a particular existing source. 213 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.” 214 Indeed, in 1988, President George Bush said that “‘progress has not come quickly enough and much remains to be done.’” 215 This time, with the 1990 CAA Amendments, Congress substantially overhauled the CAA. In particular, Congress again added to the NAAQS program, completely revised CAA section 112, added a new title to target existing fossil fuel-fired stationary sources and address growing concerns with acid rain, imported an operating permit modeled off the Clean Water Act, and established a phase out of certain ozone depleting substances. 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

213 This concept was already reflected in the EPA’s CAA section 111(d) implementing regulations under 40 C.F.R. § 60.24(f). See 40 F.R. 53340, 53347 (Nov. 17, 1975). 214 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 215 H.R. Rep. No. 101-490, at 144 (May 17, 1990).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 171 of 1275 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. 216 However, the repeal would only apply so long as the SO 2 cap under CAA section 403(e) of the newly established acid rain program remained in effect. 217 Lastly, Congress instructed the EPA to revise its new source performance standards for SO 2 emissions from fossil fuel-fired power plants but required that the revised emission rate be no less stringent than before. 218 H. Clean Power Plan Proposal and Supplemental Proposal On June 18, 2014, the EPA proposed emission guidelines for states to follow in developing plans to address greenhouse gas (GHG) emissions from existing fossil fuel-fired electricgenerating units (EGUs). Specifically, the EPA proposed ratebased goals for carbon dioxide (CO 2 ) emissions for each state with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those goals. On November 4, 2014, the EPA published a supplemental proposal that proposed emission rate-

216 Congress also updated the regulatory schedule that was added in the 1977 CAA Amendments to reflect the newly enacted 1990 CAA Amendments. See “Clean Air Act Amendments of 1990,” § 108, 104 Stat. 2467.

217 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631.

218 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 172 of 1275 based goals for CO 2 emissions for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs. In the supplemental proposal, the EPA also solicited comment on authorizing jurisdictions (including any states, territories and areas of Indian country) without existing fossil fuel-fired EGUs subject to the proposed emission guidelines to partner with jurisdictions (including any states) that do have existing fossil fuel-fired EGUs subject to the proposed emission guidelines in developing multi-jurisdictional plans. The EPA also solicited comment on the treatment of renewable energy, demand-side energy efficiency and other new low- or non-emitting electricity generation across international boundaries in a state plan. The EPA also issued two notices after the June 18, 2014 proposal. On October 30, 2014, the EPA published a notice of data availability (NODA) in which the agency provided additional information on several topics raised by stakeholders and solicited comment on the information presented. The notice 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 2 goals are calculated.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 173 of 1275 In a separate action, the EPA published a notice regarding potential methods for determining the mass that is equivalent to

an emission rate-based CO 2 goal (79 FR 67406; November 13, 2014). With the notice, the EPA also made available, in the docket for this rulemaking, a technical support document (TSD) that provided two examples of how a state, U.S. territory or tribe

could translate a rate-based CO 2 goal to total metric tons of CO 2 (a mass-based equivalent).

J. Stakeholder Outreach and Consultations Following the direction in the Presidential Memorandum to the Administrator (June 25, 2013), 219 the EPA engaged in extensive and vigorous outreach to stakeholders and the general public at every stage of development of this rule. Our outreach has included direct engagement with the energy and environment officials in states, tribes, and a full range of stakeholders including leaders in the utility power sector, labor leaders, non-governmental organizations, other federal agencies, other experts, community groups and members of the public. The EPA participated in more than 300 meetings before the rule was proposed and more than 300 after the proposal.

219 Presidential Memorandum – Power Sector Carbon PollutionStandards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 174 of 1275 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, 220 concerns, and technical information. The agency received 4.3 million comments about all aspects of the proposed rule and thousands of people participated in the agency’s public hearings, webinars, listening sessions, 221 teleconferences and meetings held all across the country. 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.

220 The EPA received more than 2,000 emails offering input intothe development of these guidelines through email and a webbased form. These emails and other materials provided to the EPA are posted on line as part of a non-regulatory docket, EPA Docket ID No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. 221 Summaries of the 11 public listening sessions in 2013 areavailable at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 175 of 1275 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. 1. Public hearings 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 176 of 1275 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.

2. State officials 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 177 of 1275 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 submitted public comments from several agencies within each state. The wealth of comments and input from states was important in developing the final rulemaking. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 178 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 179 of 1275

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 the Clean Power Plan, 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 energy efficiency and renewable

energy. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 180 of 1275 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, energy efficiency and renewable energy to reduce carbon

emissions. 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, D.C., and tribes after the rulemaking process and throughout implementation.

3. Tribal officials*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 181 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 182 of 1275 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 renewable energy 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 183 of 1275 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.

4. U.S. territories

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. 5. Industry representatives 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 184 of 1275 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 renewable energy and energy efficiency. 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. 6. Electric utility representatives 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).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 185 of 1275 7. Electricity grid operators The EPA had a number of conversations with the Independent System Operators and Regional Transmission Organizations (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. 8. Representatives from community and non-governmental organizations Agency officials engaged with community groups representing low-income 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 D.C. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 186 of 1275 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 energy efficiency and low-cost carbon reductions. In winter/spring 2015, EPA continued to offer webinars and teleconferences for community groups on the rulemaking. 9. Environmental Justice Organizations 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 187 of 1275 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. 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 2 , a key contributor to climate change, which*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 188 of 1275 adversely and disproportionally affects vulnerable and disadvantaged communities in the US and throughout the world. In addition, the rule will result in substantial reductions of conventional air pollutants, providing immediate public health

benefits to the communities where the facilities are located and for many miles around. The EPA is committed to ensuring that all Americans benefit from the public health and other benefits that this rule will bring. Further discussion of the impacts of this rule on communities and actions that the EPA is taking to address concerns cited by communities is available in Sections IX and XII.J of this preamble.

10. Labor 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 International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers (IBB); United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of the United States and Canada; the International Brotherhood of Electrical Workers (IBEW): and the Utility Workers Union of America. In addition, agency leaders

met with the Presidents of several unions and the President of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 189 of 1275 the American Federation of Labor-Congress of Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters. 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. 11. Other federal agencies and independent agencies 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 and advice 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 energy efficiency. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 190 of 1275 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. K. Comments on the Proposal The Administrator signed the proposed emission guidelines on June 2, 2014, and, on the same day, the EPA made this version*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 191 of 1275 available to the public at http://www.epa.gov/cleanpowerplan/

. The 120-day public comment period on the proposal began on June 18, 2014, the day of publication of the proposal in the Federal Register . On September 18, 2014, in response to requests from stakeholders, the EPA extended the comment period by 45 days, to December 1, 2014, giving stakeholders over 165 days to review and comment upon the proposal. Stakeholders also had the opportunity to comment on the NODA, as well as the notice and

TSD regarding potential methods for determining the mass that is equivalent to an emission rate-based CO 2 goal , through December 1, 2014. The EPA offered a separate 45-day comment period for the November 4, 2014 supplemental proposal, and that comment period closed on December 19, 2014.

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. **III. Rule Requirements and Legal Basis**

A. Summary of Rule Requirements*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 192 of 1275 The EPA is establishing emission guidelines for states to use in developing plans to address greenhouse gas 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 2 emission performance rates, state-specific goals, requirements for state plan components, and requirements for the process and timing for state plan submittal and compliance. 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 any combination of one or more measures from the following three sets of measures or building blocks:*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 193 of 1275 1. Reducing the carbon intensity of generation at individual affected coal-fired steam EGUs through heat rate improvements.2. Substituting increased generation from loweremitting existing natural gas combined cycle units for reduced generation from higher-emitting affected steam generating units. 3. Substituting increased generation from new low- and zero-emitting generating units for reduced generation from affected fossil fuel-fired generating units. Consistent with CAA section 111(d), 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 1,290 lb/MWh of CO 2 . For stationary combustion turbines, we are finalizing a performance rate of 780 lb/MWh of CO 2 . The EPA has also translated the source subcategory-specific CO 2 emission performance rates into equivalent statewide rate-based and mass-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 194 of 1275

based CO 2 goals and is providing those as an option for states to

use. 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 goal, as provided by the EPA in this rulemaking. For these final emission guidelines, the term “state,” when used in the context of section 111(d) plans, encompasses the 50 states, 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 eligible to develop and implement a CAA section 111(d) plan. However, such a “state” would not be obligated or potentially eligible to submit a CAA section 111(d) plan unless it has within its jurisdictional boundaries one or more affected EGUs that commenced construction on or before January 8, 2014. 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 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 195 of 1275 emission performance rates or the state-specific CO 2 emission goal to affected EGUs in the form of federally enforceable emission standards. With a state measures approach, a state plan would be comprised, at least in part, of measures implemented by the state that are not included as federally enforceable components of the plan, along with a backstop of federally

enforceable emission standards for affected EGUs that would apply in the event the plan does not achieve its anticipated

level of CO 2 emission performance. The EPA is requiring states to make their initial plan submittals 13 months from the signature date of the rule and to make their final plan submittals no later than 3 years from the signature date of the rule. The EPA is establishing an eight-year interim period over which states must achieve the full required reductions to meet

the CO 2 performance rates, and this begins in 2022. This eightyear interim period from 2022 through 2029, is separated into three steps, 2022-2024, 2025-2027, and 2028-2029, each

associated with its own interim CO 2 emission performance rates that states must meet, as explained in Section VI of this preamble. Affected EGUs must achieve the final emission performance rates or equivalent statewide goals by 2030 and

maintain that level thereafter.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 196 of 1275 The EPA is further establishing, as part of the guidelines, timetables for states to submit their plans. Each state must use the established electronic submittal system to provide the EPA its complete plan submittal by August 31, 2016. However, if a state needs additional time to provide the EPA with a complete plan submittal, the state must provide an initial plan submittal by August 31, 2016, that documents the reasons that more time is needed to provide a complete plan submittal and includes commitments to take concrete steps that will ensure that the state will submit a complete plan by August 31, 2018. For the final emission guidelines, the EPA is revising the list of components required in a 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:

• Description of the plan approach and geographic scope

• Identification of state state CO 2 interim period goal (for 2022-2029), interim steps (interim step goal 1 for 2022- 2024; interim step goal 2 for 2025-2027; interim step goal 3 for 2028-2029) and final CO 2 emission goal of 2030 and beyond

• Demonstration that the plan submittal is projected to achieve the state ’ s CO 2 emission goal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 197 of 1275

• State recordkeeping and reporting requirements

• Certificatin of hearing on state plan

• Supporting documentation Also, in all state plans, as part of the supporting documentation, states must include a description of their required consultation with relevant ISOs/RTOs and/or planning/reliability authorities during plan development, including any recommendations and other comments provided by

those authorities. Further, the EPA is requiring that states provide, in their initial plan submittal, a summary of how they have been engaging with community stakeholders and how they intend to meaningfully engage with community stakeholders during the additional time (if an extension is granted) for development of the final plan. In their report, states must show how they identified low income and communities of color that they are conducting meaningful community engagement with in the state plan development process. For the final plan submittal, states must engage with all members of the public, including communities, during the complete plan development process pursuant to the public participation requirements of the framework regulations. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 198 of 1275 EGUs; and monitoring, recordkeeping and reporting requirements.

 Demonstrations that each emission standard is 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 is 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 letter submitted to the EPA by August 31, 2016. In the case of a

tribe that has one or more affected EGUs in its area of Indian country, 222 the tribe has the opportunity, but not the

222 The EPA is aware of at least four affected EGUs located in Indian country: two on Navajo lands, the Navajo Generating Station and the Four Corners Power Plant; one on Ute lands, the Bonanza Power Plant; and one on Fort Mojave lands, the South Point Energy Center. The affected EGUs at the first three plants are coal-fired EGUs. The fourth affected EGU is an NGCC facility.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 199 of 1275 obligation, to establish a CAA section 111(d) plan for its area of Indian country. If a tribe with one or more affected EGUs located in its area of Indian country does not submit a 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. During and following implementation of its 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. B. Legal Basis This rule is consistent with the requirements of CAA section 111(d) and the implementing regulations. As an initial matter, the EPA reasonably interprets the provisions identifying which air pollutants are covered under CAA section 111(d) to authorize the EPA to regulate CO 2 from fossil fuel-fired EGUs. In addition, the EPA recognizes that CAA section 111(d) applies to sources that, if they were new sources, would be covered under a CAA section 111(b) rule. Concurrently with this rule, the EPA is finalizing a CAA section 111(b) rulemaking establishing*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 200 of 1275 standards of performance for CO 2 emissions from new fossil fuelfired EGUs, from modified fossil fuel-fired EGUs, and from reconstructed fossil fuel-fired EGUs, and any of those sets of section 111(b) standards of performance provides the requisite predicate for this rulemaking. 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; 223 accordingly, in this rulemaking, the EPA is determining

the BSER. The EPA is finalizing the BSER for fossil fuel-fired EGUs based on building blocks 1, 2, and 3. Building block 1 includesoperational improvements and equipment upgrades that the coalfired 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

223 The EPA is not re-opening that interpretation in this rulemaking.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 201 of 1275“reasonable.” Building blocks 2 and 3 include increases in lowor zero-emitting generation which substitute for generation from the affected EGUs and thereby reduce CO 2 emissions from those sources. All of these measures are components of a “system of emission reduction” for the affected EGUs because they entail actions that the affected EGUs may themselves undertake that have the effect of reducing their emissions. Further, these measures meet the criteria in CAA section 111(a)(1) and the case law for the “best” system of emission reduction that is “adequately demonstrated” because they achieve the appropriate level of reductions, their cost is “reasonable,” they do not have adverse non-air quality health and environment impacts orimpose adverse energy requirements, and they are each wellestablished among affected EGUs. It should be emphasized that

these measures are consistent with current trends in the electricity sector. Building blocks 2 and 3 include reduced generation from the fossil fuel-fired EGUs because that is a step in the process ofsubstituting lower- or zero-emitting generation for higheremitting generation. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 202 of 1275 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 within the BSER as well. As a result, an affected EGU has a set of choices for achieving its emission standards. It 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 measures through a set of actions that range from purchasing full or partial interest in existing NGCC or new renewable energy assets to purchasing emission rate credits 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. In addition, the affected EGU may purchase rate-based emission credits from other affected EGUs. If the state chooses to impose a mass-based emission standard, the affected EGU 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 203 of 1275 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 2 emission performance rates established by the EPA or the equivalent statewide rate-based or mass-based goal provided by the EPA in this rule. The EPA interprets CAA section 111(d) to allow states to establish standards of performance and provide for their implementation and enforcement through either the “emission standards” or the “state measures” plan type. In the case of the “emission standards” plan type, the emission standards establish standards of performance, and the other components of the plan provide for their implementation and enforcement. In the case of the “state measures” plan type, the state submits standards of performance in the form of a federally enforceable backstop, the trigger mechanism provides for the implementation of such backstop, and the other components of the plan also provide for implementation and enforcement of the standards of performance. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 204 of 1275 have deployed or will deploy in the electricity sector that

reduce CO 2 emissions from affected EGUs. It should be noted that both state plan types allow the state flexibility in assigning the emission performance obligations to its affected EGUs in the form of standards of performance as long as the required emission performance level is met. Both plan types harness the efficiencies of emission reduction opportunities in the interconnected electricity system and are fully consistent with the principles of cooperative federalism that underlie the Clean Air Act generally and CAA section 111(d) particularly. That is, both plan types achieve the emission performance requirements through the vehicle of a state plan, and provide each state significant flexibility to take local circumstances and state policy goals into account in determining how to reduce emissions from its affected sources, as long as the plan meets minimum federal requirements. 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 2 emission performance rate or state goal by the affected EGUs,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 205 of 1275

and is not limited to the measures that the EPA identifies as part of the BSER. 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 discusses certain issues in more detail in the Legal Memorandum included in the docket for this rulemaking. **IV. Authority for this Rulemaking, Definition of Affected Sources, and Treatment of Source Categories**  A. EPA’s Authority under CAA Section 111(d) 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 206 of 1275 U.S.C. 7411(d)(1)(A)(i). Second, section 111(d) applies only to air pollutants for which the existing source would be regulated

under section 111 if it were a new source. 42 U.S.C. 7411(d)(1)(A)(ii). Here, carbon dioxide (CO 2 ) meets both criteria: (1) it is not a criteria pollutant regulated under section 108 nor a HAP regulated under CAA section 112, and (2)

CO 2 emissions from new power plants (including newly constructed, modified and reconstructed power plants) are regulated under the CAA section 111(b) rule published today along with this rule. B. CAA Section 112 Exclusion to CAA Section 111(d) Authority CAA section 111(d) contains an exclusion that limits the regulation 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 passed different amendments to the Section 112 Exclusion and both amendments were signed into law. In 2005, in connection with the Clean Air Mercury Rule (CAMR), the EPA discussed the agency’s interpretation of the exclusion in light of these two differing amendments and concluded that the two amendments were in conflict, should be read to give both meaning, and should be*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 207 of 1275 interpreted as follows: 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). In June 2014, the EPA presented this previous interpretation along with the proposed rule 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 2 emissions from power plants. In particular, many comments focused on two specific issues. First, some commenters -- including some industry and state commenters that had previously endorsed the EPA’s interpretation

of the Section 112 Exclusion in other contexts 224 -- argued that

224 For example, in the CAMR litigation (State of New Jersey v. EPA, No. 05-1097 (D.C. Cir.) , the joint brief filed by a group of intervenors and an amicus (including six states and the West Virginia Department of Environmental Protection, and Utility Air Regulatory Group and nine other industry entities) stated that the EPA had interpreted section 111(d) in light of the two*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 208 of 1275 the EPA’s 2005 interpretation was in error because it allowed the regulation of certain pollutants from source categories under CAA section 111(d) when those categories were also regulated for different pollutants under CAA section 112. Second, some commenters argued that the EPA’s previous interpretation of the House amendment (as originally represented in 2005 at 70 FR at 16029-30) was in error because it improperly read that amendment as focusing on whether a source category was regulated under CAA section 112 rather than on whether the air pollutant was regulated under CAA section 112, and that improper reading lead to an interpretation that was inconsistent with the structure and purpose of the CAA. 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 2 from power plants given that power plants are regulated for certain HAP under CAA section 112. On this issue, the EPA has concluded that the two differing amendments are not properly read as conflicting. Instead, the House amendment and the Senate Amendment should

different amendments and that the EPA’s interpretation was “a reasoned way to reconcile the conflicting language and the Court should defer to the EPA’s interpretation.” Joint Brief of State Respondent-Intervenors, Industry Respondent-Intervernors, and State Amicus, filed May 18, 2007, at 25.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 209 of 1275

each be read to mean the same in this context: that the Section 112 Exclusion does not bar the regulation under CAA section 111(d) of any non-HAP from a source category, regardless of whether that source category may be subject to standards for HAP under CAA section 112. In reaching this conclusion, the EPA has revised its previous interpretation of the House amendment, as

discussed below. The EPA’s analysis is entitled to deference under the principles established in Chevron v. NRDC, 467 U.S. 837 (1984). See White Stallion Energy v. EPA, 748 F.3d 1222, 1235 (D.C. Cir. 2014) (a revision to an agency interpretation is reviewed under the Chevron framework. Under that framework, the revised interpretation will be upheld if the court finds that it “is permissible under the statute, that there are good reasons for it, and that the agency believes it to be better.”) (quoting FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)). 225 The EPA’s revised interpretation is discussed below.

1. Structure of the CAA and Pre-1990 Section 112 Exclusion The Clean Air Act sets out a comprehensive scheme for air pollution control, addressing three general categories of

225 Indeed, the Chevron case itself involved the EPA’s reevaluation of how to interpret an ambiguous statutory term. See 467 U.S. at 857-58 (EPA reevaluation of how to interpret the term “source”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 210 of 1275 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 Fed. Reg. 53,340 (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. Hazardous air pollutants 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 211 of 1275 EPA will publish and revise a list of “major” and “area” source categories of hazardous pollutants, and then establish emissions standards for hazardous air pollutants emitted by sources within a 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. CAA section 111 has two main components. First, CAA section 111(b) requires the EPA to promulgate federal “standards of performance” addressing new stationary sources that cause or contribute significantly to “air pollution which may reasonably be anticipated to endanger public health or welfare.” 42 U.S.C. § 7411(b)(1)(A). Once the EPA has set new source standards addressing emissions of a particular pollutant, CAA section 111(d) provides that the EPA will promulgate regulations requiring states to establish standards of performance for existing stationary sources of the same pollutant. 42 U.S.C. § 7411(d)(1). 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 212 of 1275 source emissions that pose any significant danger to public health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 226 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) regulation of pollutants is intended to cover pollutants that are not regulated under either the criteria pollutant/NAAQS provisions or the hazardous air pollutants regulated under 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 between the criteria pollutant provisions and 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

226 In subsequent CAA amendments, Congress has maintained this three-part scheme, but supplemented it with the Preservation of Significant Deterioration (PSD) program, the Acid Rain Program and the Regional Haze program.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 213 of 1275 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.”).

2. The 1990 Amendments to the Section 112 Exclusion 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 hazardous air pollutants; set criteria for listing “source categories” of such pollutants; and required the EPA to establish standards for each source category*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 214 of 1275 or subcategory’s hazardous pollutant emissions. 42 U.S.C. § 7412(a), (b)(1) & (2), & (d)(1). In the course of overhauling the regulation of hazardous air pollutants under section 112, Congress needed to edit section 111(d), which cross-referenced a provision of old section 112 that was to be eliminated – section 112(b)(1)(A).

To address the obsolete cross-reference to section 7412(b)(1)(A), Congress passed two differing amendments – one

from the House and one from the Senate – that were never reconciled in conference. The House amendment replaced the cross-reference with the phrase “emitted from a source category which is regulated under section [112].” Pub. L. No. 101-549, § 108(g), 104 Stat. 2399, 2467 (1990). The Senate amendment replaced the same text with a cross-reference to new section 112. Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 2574 (1990). Both amendments were enacted into law, and are thus both are part of the current CAA. To determine how this this provision is properly applied in light of the two differing amendments, we first look at the Senate amendment, then at the House amendment, then discuss how the two amendments are properly read together.

3. The Senate Amendment is Clear and Unambiguous Unlike the ambiguous amendment to section 111(d) in the House amendment (discussed below), the Senate amendment is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 215 of 1275 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. No. 101-549, § 302(a), 104 Stat. 2399, 2574 (1990). So amended, 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 not preclude the EPA from regulating CO 2 from power plants notwithstanding that power plants are also regulated for HAP

under CAA section 112 under the MATS rule. 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 amendments 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. No. 101-549, §§ 108(g) and 302(a), 104 Stat.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 216 of 1275 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); Stephan v. United States, 319 U.S. 423, 426 (1943) (“the Code cannot prevail over the Statutes at Large when the two are inconsistent”); Five Flags Pipe Line Co. v. Dep’t of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) (“[W]here the language of the Statutes at Large conflicts with the language in the United States Code that has not been enacted into positive law, the language of the Statutes at Large controls.”). Second, the “conforming” label is irrelevant. A“conforming” amendment may be either substantive or nonsubstantive. Burgess v. United States, 553 U.S. 124, 135 (2008). And while the House Amendment contains more words, it also qualifies as a “conforming” amendment under the definition in the Senate Legislative Drafting Manual, Section 126(b)(2) (defining “conforming amendments” as those “necessitated by the substantive amendments of provisions of the bill”). Here, both the House and Senate amendments were “necessitated by” Congress’ revisions to section 112 in the 1990 CAA Amendment, which included the deletion of old section 112(b)(1)(A). Thus, the House’s amendment is no less “conforming” than the Senate’s, and the heading under which it was enacted (“Miscellaneous*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 217 of 1275 Guidance”) does not suggest any more importance than “Conforming Amendments.” In any event, courts gives full effect to conforming amendments, see Washington Hosp. Ctr. v. Bowen, 795 F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate Amendment nor the House amendment can be ignored. 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

over 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 S. 1630, as reported (Dec. 20,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 218 of 1275 1989), 1990 CAA Legis. Hist. at 7906. As reported and eventually passed, S. 1630 did not contain the text in the House amendment (“or emitted from a source category which is regulated under section 112”) and instead contained the substitution of cross references (changing “section 112(b)(1)(A)” to “section 112(b)”) as a “conforming” amendment. See S. 1630, as reported, 101 st Cong. § 305, 1990 CAA Legis. Hist. at 8153; S. 1630, as passed, § 305 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 4534. Though the EPA is not aware of any statements in the legislative history that expressly explain the Senate’s intent in making these changes to the Senate bill, the sequence itself supports the

conclusion that the Senate’s substitution reflects a decision to retain the pre-1990 approach of using a cross-reference to 112(b) to define the scope of the Section 112 Exclusion. Whether the difference in approach between the final Senate amendment in

S.1630 and the House amendment in H.R. 3030 creates a substantive difference or are simply two different means of achieving the same end depends on what interpretation one gives to the text in the House amendment, which we turn to next.

4. The House Amendment

a. The House Amendment is Ambiguous. Statutory interpretation begins with the text, but does not end there. As the D.C. Circuit Court has explained, “[t]he literal language of a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 219 of 1275 provision taken out of context cannot provide conclusive proof of congressional intent.” Bell Atlantic Telephone Cos. v. F.C.C., 131 F.3d 1044, 1047 (D.C. Cir. 1977). Rather, a proper reading of statutory text “must employ all the tools of statutory interpretation, including text, structure, purpose, and legislative history.” Loving v. I.R.S., 742 F.3d 1013, 1016 (D.C. Cir. 2014) (internal quotation omitted). See, also,

Robinson v. Shell Oil Co

. , 519 U.S. 337, 341 (1997) (statutory interpretation involves consideration of “the language itself, the specific context in which that language is used, and the broader context of the statute as a whole.”). Moreover, one principle of statutory construction that has particular application here is that provisions in a statute should be read to be consistent, rather than conflicting, if possible. This principle was discussed in the recent case of Scialabba v. Cuellar De Osorio, 134 S. Ct. 2191, 2214 (concurring opinion by Chief Justice Roberts and Justice Scalia), 2219-2220 (dissent by Justices Sotomayor, Breyer and Thomas). As Justice Sotomayor wrote (at 134 S. Ct. at 2220): “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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 220 of 1275 statute] into [a] harmonious whole.” FTC v. Mandel Brothers, Inc., 359 U.S. 385, 389, 79 S. Ct. 818, 3 L. Ed. 2d 893 (1959); see also Morton v. Mancari, 417 U.S. 535, 551, 94 S. Ct. 2474,41 L. Ed. 2d 290 (1974) (when two provisions “are capable of coexistence, it is the duty of the courts . . . to regard each as effective”). In reviewing an agency’s construction of a statute, courts “must,” we have emphasized, “interpret the statute ‘as a . . . coherent regulatory scheme’” rather than an internally inconsistent muddle, at war with itself and defective from the day it was written. Brown & Williamson, 529 U.S., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 121.” 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. Two possible readings are based on its literal text, but neither of those readings is reasonable and no one has advocated that either of those readings be adopted. Further, there are additional interpretations that arise from different readings of the ambiguous phrases and structure created by the House amendment. As discussed below, two of these additional interpretations are unreasonable, while

three are reasonable. First, the literal text of the House-amended version of CAA section 111(d) could be read as authorizing the regulation of any pollutant that is not a criteria pollutant. This*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 221 of 1275 interpretation becomes apparent 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, one reading of the literal language of section 111(d) provides that the Administrator may require states to establish standards for an air pollutant so long as either air quality criteria have not been established for that pollutant, or one of the remaining criteria is met. If this reading were applied to determine whether the EPA may regulate CO 2 from power plants under section 111(d), the analysis would be (a) air quality criteria have not

been issued for CO 2 , (b) whether CO 2 or power plants are regulated under section 112 is irrelevant, and (c) CO 2 emissions from power plants may be regulated under section 111(d). This interpretation, however, is not a reasonable reading of the statute because, among other reasons, it gives little or no*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 222 of 1275 meaning to the limitation covering hazardous air pollutants that are regulated under CAA section 112 and thus is contrary to both the CAA’s comprehensive scheme created by the three sets of provisions (under which CAA section 111 is not intended to duplicate the regulation of pollutants regulated under section112) and the principle of statutory construction that text should not be construed such that a provision does not have

effect. A second literal reading of CAA section 111(d) as revised by the House amendment arises from 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” require standards for “any air pollutant . . . emitted from a source category which is regulated under section [112].” 42 U.S.C. § 7411(d)(1). Thus, section 111(d) could be read literally as requiring EPA to regulate emissions of pollutants from a source category under*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 223 of 1275 section 111(d) if that source category is regulated under CAA section 112. If this reading were applied to the question of the EPA’s authority for this rule, the result would be that the EPA not only has the authority to regulate CO 2 from power plants, but became obligated to do so once power plants were regulated under section 112. Again, this interpretation is not reasonable because it would not only call for the regulation under CAA section 111(d) of pollutants that were not regulated under CAA section 112, but would also provide for the regulation of a source’s HAP emissions under CAA section 111(d) when those same emissions were also subject to standards under CAA section 112. Thus, this reading would be contrary to the comprehensive scheme of the statute under which CAA section 111(d) regulation is intended to fill the gap between the other programs by covering pollutants that the other programs do not, and not duplicate the regulation of pollutants that the other programs cover. Turning now to the interpretation of the ambiguous phrases and structure created by the House amendment, 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 224 of 1275 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 section 111(d). The phrase “regulated under section 112” is ambiguous, first, because the sentence structure in the text does not make clear what that phrase is intended to modify. Young v. Community Nutrition Inst., 476 U.S. 974, 980-81 (1986) (“As enemies of the dangling participle well know, the English language does not always force a writer to specify which of two possible objects is the one to which a modifying phrase relates.”) Second, 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 Rush Prudential HMO, Inc. v. Moran, 536 U.S. 355, 366 (2002) (It is necessary to “pars[e] . . . the ‘what’” of the term “regulates.”); UNUM Life Ins. Co. of Am. v. Ward, 526 U.S. 358, 363 (1999) (the term “‘regulates insurance’ . . . requires interpretation, for [its] meaning is not plain.”). Here, one possible reading is that the phase modifies the words “a source category” without regard to what pollutants are regulated under section 112, which then presents the issue of what meaning to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 225 of 1275 give to the phrase “a source category” and leads to a third and fourth interpretation of the House amendment. In this context, a third interpretation of the Section 112 Exclusions arises if one reads “a source category” to mean “any” source category. Under this third interpretation of the House amendment, CAA section 111(d) regulation is limited to air pollutants that are not emitted by any source category for which

the EPA has issued standards for HAP under CAA section 112. But this interpretation would read CAA section 111(d) out of the statute. Given the extensive list of source categories regulated under CAA section 112 and the breadth of the pollutants emitted by those categories collectively, literally all air pollutants would be barred from CAA section 111(d) regulation under this interpretation, because any given air pollutant is emitted by at least one source category for which the EPA has issued standards

for HAP under the mandate of CAA section 112. Based on the principle that statutes should be interpreted such that all parts of it have meaning, see, e.g., Mountain States Tel. & Tel. v. Pueblo of Santa Anna, 472 U.S. 237, 249 (1985), the EPA concludes this is not a reasonable interpretation of the House

amendment. A fourth interpretation would read the words “a source category” to mean the particular source category, again without*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 226 of 1275 regard to the scope of pollutants that are regulated under CAA section 112, and interpret the House amendment to 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. The effect of this reading would be to preclude the regulation of CO 2 from power plants under CAA section 111(d) because power plants have been regulated for hazardous air pollutants under CAA section 112. This is the interpretation that the EPA applied to the House amendment in connection with the CAMR rule in 2005, when looking at the question of whether HAP can be regulated under CAA section 111(d) for a source category that is not regulated for HAP under section 112, and some commentors have advocated for this interpretation. But, after considering all of the comments and reconsidering this interpretation, the EPA has concluded that this interpretation of the Section 112 Exclusion as amended by just the House amendment is not a reasonable reading because it would disrupt the comprehensive scheme for regulating existing sources created by the three sets of provisions covering criteria pollutants, hazardous air pollutants and the other pollutants that fall outside of those two programs. 227

227 In assessing any interpretation of section 111(d), EPA must consider how the three main programs set forth in the CAA work*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 227 of 1275 Specifically, under this fourth interpretation, the EPA could not both (a) regulate a source category’s emissions of hazardous air pollutants under CAA section 112, and (b) regulate that category’s other pollutants under section 111(d). There is no

reason to conclude that the House amendment was intended to abandon the existing structure and relationship between the three programs in this way. Indeed, Congress expressly provided that regulation under CAA section 112 was not to “diminish orreplace the requirements of” the EPA’s regulation of nonhazardous pollutants under section 7411. 42 U.S.C. § 7412(d)(7). Further, consistent with CAA section 112’s direction that EPA list “all categories and subcategories of major sources and area [aka, non-major] sources” of HAP and then establish CAA section 112 standards for those categories and subcategories, 42 U.S.C. §§ 7412(c)(1) and (c)(2), the EPA has listed and regulated over 140 categories of sources under CAA section 112. Thus, similar to the third reading above, this reading would prevent section 111(d) from serving as the gap-filling provision within the comprehensive scheme of the CAA. For these reasons, and as further discussed [below/in the Response to Comments], it is not

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory interpretation must account for . . . the broader context of the statute as a whole”) (quotation omitted).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 228 of 1275 reasonable to interpret the CAA section 112 exclusion in section 111(d) to mean that the existence of CAA section 112 standards covering hazardous pollutants from a source category would entirely eliminate regulation of non-hazardous emissions from that source category under section 111(d). 228

b. The EPA’s Interpretation of the House Amendment. Having concluded that the interpretations discussed above are not reasonable, the EPA has identified three reasonable interpretations of the House amendment. First, one could interpret the House amendment to mean that the Section 112 Exclusion excludes the regulation of HAP if the source category at issue is regulated under CAA section 112, but does not exclude the regulation of other pollutants, regardless

228 Some commenters have stated that EPA could chose to regulate both HAP and non-HAP under section 111(d), and thus could regulate HAP without creating a gap. But this presumes that Congress intended EPA to have the choice of declining to regulate a section 112-listed source category for HAP under section 112, which is inconsistent with the mandatory language in section 112. See, e.g., section 112(d)(1)(“The Administrator shall promulgate regulations establishing emissions standards for each category or subcategory of major sources and area sources of hazardous air pollutants listed for regulation pursuant to subsection (c) of this section in accordance with the schedules provided in subsections (c) and (e) of this section.”). Moreover, given the prescriptive language that Congress added into section 112 concerning how to set standards for HAP, see section 112(d)(2) and (d)(3), it is unreasonable to conclude that Congress intended that EPA could simply choose to ignore the provisions in section 112 and instead regulate HAP for a section 112 listed source category under section 111(d).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 229 of 1275 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 fourth interpretation discussed above) but also recognizes that the phrase “regulated under section 112” refers to the regulation of HAP emissions. In other words, this 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 first reasonable 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). Second, one could interpret the House amendment to mean that the Section 112 Exclusion always excludes the regulation of CAA section 112 pollutants, but does not exclude other*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 230 of 1275 pollutants, and the scope of the exclusion is the same regardless of whether the source category is subject to standards under CAA section 112. This interpretation of the House amendment reads the phrase “regulated under section 112” as modifying “air pollutant” rather than “source category” and reads the phrase “emitted by a source category” as having minimal import because it is the remnant of phrasing that was originally intended to be an exclusion within CAA section 112 for source categories regulated under section 111. 229 A key

229 Originally, when the House bill to amend the CAA was introduced in January 1989, it focused on amendments to control HAP. Of particular note, the amendments to CAA section 112 included a provision that excluded regulation under section 112 of “[a]ny air pollutant which is included on the list under section 108(a), or which is regulated for a source category under CAA section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA Legist. Hist. at 4046. In other words, the Section 112 Exclusion in CAA section 111(d) that was ultimately contained in the House amendment was originally crafted as what might be called a “Section 111(d) Exclusion” in CAA section 112. This is significant because the “source category” phrasing in the original January 1989 text with respect to CAA section 111(d) makes sense, whereas the “source category” phrasing in the 1990 House amendment does not. When referring to the scope of what is regulated under section 111(d), it makes sense to frame that scope with respect to source categories, because CAA section 111 regulation begins with the identification of source categories under CAA section 111(b)(1)(A). By contrast, regulation under CAA section 112 begins with the identification of HAP under CAA section 112(b); the listing of source categories under section 112(c) is secondary to the listing of HAP. From this history, and in light of this difference between the scope of what is regulated in CAA sections 111 and 112, it is reasonable to conclude that the “source category” phrasing is a legacy from the original 1989 bill—that is, when converting the 1989 text*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 231 of 1275 distinction between this second reasonable interpretation and the first reasonable interpretation discussed above is that this second reasonable interpretation concludes that HAP can never be regulated under CAA section 111(d). Third, one could interpret the House amendment to mean that

the Section 112 Exclusion excludes all of the CAA section 112 pollutants that have actually been regulated for at least one source category under CAA section 112, but does not exclude other pollutants (that is, pollutants that are not listed under CAA section 112). This third reasonable interpretation reads the phrase “a source category” as meaning “any” source category listed under section 112 and the phrase “regulated under section 112” in light of the fact that a source category is “regulated under 112” with respect to HAP and not other pollutants. Thus, under this third reasonable interpretation of the House amendment, the scope of the Section 112 Exclusion does not cover

non-HAP. These three interpretations share a number of common reasons why they are reasonable and avoid the issues discussed

above.

into the Section 112 Exclusion that we see in the 1990 House amendment, the legislative drafters continued to use phrasing based on “source category” notwithstanding that this phrasing created a mismatch with the way that the scope of CAA section 112 regulation is determined.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 232 of 1275 First, all three of these reasonable interpretations read the House amendment to the Section 112 Exclusion as determining the scope of what air pollutants are 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 do also address the question of what air pollutants may be regulated under CAA section 111(d) is

consistent with the overall nature of the text in which it

appears. Second, all three reasonable interpretations further – rather than undermine – the purpose of CAA section 111(d) within the long-standing structure of the CAA. That is, these interpretations support 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. Third, by avoiding the creation of gaps in the statutory structure, all three interpretations are 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 233 of 1275 pollutants, under more programs, more quickly. 230 Conversely, the the EPA is aware of no statement in the legislative history indicating that Congress simultaneously sought to restrict the EPA’s authority under CAA section 111(d) or to create gaps in the comprehensive structure of the statute. If Congress had intended this amendment to make such a change, one would expect to see some indication of that in the legislative history. Fourth, when applied in the context of this rule, all three of these reasonable interpretations of the House amendment are consistent with the Senate amendment. Thus, these interpretations in this context avoid creating a conflict within the statute and fulfill that principle of statutory construction. See discussion above of Scialabba, 134 S. Ct. 2191

230 See S. Rep. No. 101-228 at 133 (“There is now a broad consensus that the program to regulate hazardous air pollutants . . . should be restructured to provide the EPA with authority to regulate industrial and area sources of air pollution . . . in the near term”), reprinted in 5 A Legislative History of the Clean Air Act Amendments of 1990 (“Legis. Hist.”) 8338, 8473 (Comm. Print 1993); S. Rep. No. 101-228 at 14 (“The bill gives significant authority to the Administrator in order to overcome the deficiencies in [the NAAQS program]”) & 123 (“Experience with the mobile source provisions in Title II of the Act has shown that the enforcement authorities . . . need to be strengthened and broadened . . .”), reprinted in 5 Legis. Hist. at 8354, 8463; H.R. Rep. No. 101-952 at 336-36, 340, 345 & 347 (discussing enhancements to Act’s motor vehicle provisions, the EPA’s new authority to promulgate chemical accident prevention regulations, the enactment of the Title V permit program, and enhancements to the EPA’s enforcement authority), reprinted in 5 Legis. Hist. at 1786, 1790, 1795, & 1997.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 234 of 1275 at 2220 (citing and quoting, among other authorities, 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”)). In sum, when either of these three reasonable interpretations of the House amendment is applied in the context of this rule, each interpretation reaches the same result: 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. Thus, in the context of this rule, the EPA does not need to decide which of these three reasonable interpretations is better.

5. The Two Amendments Are Easily Reconciled And Can Be Given Full

Effect

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) allows the EPA to regulate non-HAP from a source category regardless of whether that source category is also regulated*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 235 of 1275 under CAA section 112. Thus, the EPA has the authority to regulate CO 2 from power plants notwithstanding that power plants are regulated for HAP under CAA section 112. C. Authority to Regulate EGUs In a separate, concurrent action, the EPA is also finalizing two CAA section 111(b) rulemakings, one that regulates CO 2 emissions from new EGUs and another that regulates

CO 2 emissions from modified and reconstructed EGUs. The promulgation of either of these is the requisite predicate for applicability of CAA section 111(d). 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 236 of 1275 “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 two rulemakings under CAA section 111(b) for CO 2 emissions from affected EGUs concurrently with this CAA section 111(d) rulemaking, which will provide the requisite predicate for applicability of CAA section 111(d). 231

D. Definition of Affected Sources

231 In the past, the EPA has issued standards of performance under section 111(b) and emission guidelines under section 111(d) simultaneously. See “Standards of Performance for new Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills – Final Rule,” 61 Fed. Reg. 9905 (March 12, 1996).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 237 of 1275 For the emission guidelines, an affected EGU is any steam generating unit, IGCC, or stationary combustion turbine that was in operation or had commenced construction as of January 8, 2014, 232 and that meets the following criteria, which differ depending on the type of unit. To be an affected source, such a unit, if it is a steam generating unit or IGCC, must serve a generator capable of selling greater than 25 MW to a utility power distribution system and have a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel). If such a unit is a stationary combustion turbine, the unit must meet the definition of a combined cycle or combined heat and power combustion turbine, serve a generator capable of selling greater than 25 MW to a utility power distribution system, and have a base load rating of greater than 260 GJ/h (250 MMBtu/h). 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

232 Under Section 111(a) of the CAA, determination of affected sources is based on the date that the EPA proposes action on such sources. January 8, 2014 is the date the proposed GHG standards of performance for new fossil fuel-fired EGUs were published in the Federal Register (79 FR 1430).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 238 of 1275 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 those that (1) 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 (i.e., units that are capable of combusting 50 percent or more non-fossil fuel) that have historically limited the use of fossil fuels to 10 percent or less of the annual capacity factor or are subject to a federally*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 239 of 1275 enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (4) stationary combustion turbines that are not capable of combusting natural gas (i.e., not connected to a natural gas pipeline); (5) are a combined heat and power unit that are subject to a federally enforceable permit limiting, or have historically limited, annual net electric sales to a utility power distribution system to the product of the design efficiency and the potential electric output or 219,000 MWh (whichever is greater) or less; (6) 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; (7) are a municipal waste combustor unit subject to subpart Eb of Part 60; or (8) are a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of Part 60. The rationale for applicability of this final rule is multi-fold. We had proposed that affected EGUs were those existing source 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 240 of 1275

include certain units that would otherwise meet the CAA section 111(b) applicability in this CAA section 111(d) emissionguidelines. These include simple cycle turbines, certain nonfossil 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 apply to 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. Further, we have not evaluated any opportunities that existing simple cycle have to reduce their heat rate. Therefore, nothing would be required of simple cycle units under building block 1. Second, the vast majority of simple cycle turbines serve a specific need – providing power during periods of peak electric demand (i.e., peaking units). The existing block of simple cycle turbines are the only units that are able to start fast enough and ramp to full load quickly enough to serve as peaking units. If these units were to be used under building block 2 to displace higher emitting coal-fired units, they would no longer*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 241 of 1275 be available to serve as peaking units. Therefore, building block 2 would not apply to simple cycle units. 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, building block 3 would not apply to 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, it would not impact the stringency of the plans. Such inclusion

would increase burden but result in no environmental benefit. Finally, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 242 of 1275 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. E. Combined Categories and Codification in the Code of Federal Regulations In this rulemaking, the EPA is combining the two existing categories for the affected EGUs into a single category for purposes of the CO 2 emissions from existing affected EGUs. The EPA is also codifying all of the requirements for the affected EGUs in a new subpart UUUU of 40 CFR part 60 and including all GHG emission guidelines for the affected sources – fossil fuel– fired electric utility steam generating units, as well as natural gas-fired stationary combustion turbines -- in that newly created subpart. 233 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 two categories will facilitate implementation of CO 2 mitigation measures, such as shifting generation from higher to lower-carbon intensity generation

233 The EPA is not codifying any of the requirements of this rulemaking in subparts Da or KKKK.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 243 of 1275 among existing sources (e.g., shifting from utility boilers to NGCC units), and emission trading among sources in both categories. 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 2 emissions from new construction of affected EGUs, and codifying the proposed requirements in a new 40 CFR part 60 subpart TTTT. For the final standards of performance for new construction of affected EGUs, the EPA is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 244 of 1275 codifying the final requirements in a new 40 CFR part 60 subpart

TTTT. In this rulemaking, the EPA is combining the two categories into a single category for purposes of the CO 2 emissions fromexisting affected EGUs. Because the two categories are preexisting and the EPA would not be subjecting any additional sources to regulation, the combined category is not considered a new category that the EPA must list under CAA section 111(b)(1)(A). As a result, this final rule does not list a new category under section 111(a)(1)(A), nor does this final rule revise either of the two source categories – steam-generating boilers and combustion turbines – that the EPA has already listed under that provision. Thus, the EPA is not required to make a finding that the combined category causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. **V. The Best System of Emission Reduction and Associated Building**

**Blocks** In the June 2014 proposal, the EPA proposed to determine that the best system of emission reduction adequately demonstrated (BSER) for reducing CO 2 emissions from existing EGUs was a combination of measures –- (1) increasing the operational efficiency of existing coal-fired steam EGUs, (2) substituting*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 245 of 1275 increased generation at existing NGCC units for generation at existing steam EGUs, (3) substituting generation from low- and zero-carbon generating capacity for generation at existing fossil fuel-fired EGUs, and (4) increasing demand-side energy efficiency to reduce the amount of fossil fuel-fired generation –- which we categorized as four “building blocks.” As an alternative to the proposed building blocks 2, 3, and 4, the EPA also identified reduced generation in the amount of those building blocks as part of the BSER. These measures are not the only approaches EGUs can take to reduce CO 2 , but are those that the EPA felt best met the statutory criteria. We solicited comment on all aspects of our BSER determination, including other approaches. We have considered thoroughly the extensive comments submitted on a variety of topics related to the BSER and the individual building blocks, along with our own continued analysis, and we are finalizing the BSER based on the first three building blocks, with certain refinements. Consistent with the approach taken in the proposed rule, in determining the BSER we have taken account of the global nature

of CO 2 pollution and the unique characteristics of the source category, particularly the exceptional degree of interconnectedness among individual affected sources and the longstanding practice of coordinating planning and operations*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 246 of 1275 across multiple sources. Each building block is a proven approach for reducing emissions from the affected sourcecategory that is appropriate in this pollutant- and industryspecific context. Each building block also encompasses a variety of actions that individual affected sources may take, including direct investment in efficiency improvements and in lower- and zero-carbon generation, cross-investment in these activities through mechanisms such as emissions trading or other multi-unit compliance approaches, and reduction of higher-carbon generation. With attention to costs 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 balanceconsideration of the various BSER factors. Additional, nonbuilding block specific aspects of the BSER quantification methodology discussed below are similarly conservative. 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. The wide range of actions encompassed in the building blocks, and a further wide range of possible emissions-reducing actions not included*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 247 of 1275 in the BSER but nevertheless available to help with compliance, ensure that the BSER is achievable by individual affected

sources as well. The final BSER reflects certain changes from the proposed rule, reflecting consideration of comments received and further analysis. The principal changes are the exclusion from the BSER of emission reductions achievable through demand-side energy efficiency and through nuclear generation; a revised approach to determination of emission reductions achievable through increased renewable energy generation, based on an alternate approach on which we solicited comment in the proposed rule; 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 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 in response to comments, in the final rule we have represented the emission limitations achievable through the BSER

in the form of uniform CO 2 emission performance rates for each of two affected source subcategories: steam generating units and stationary combustion turbines. However, like the proposed rule,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 248 of 1275 the final rule also provides weighted-average state-specific goals that a state may choose as an alternative to the nationwide subcategory-based CO 2 emission performance rates. The change to uniform CO 2 emission performance rates is discussed in this section and in section VI of the preamble, and the relation of the performance rates to the state-specific goals and states’ section 111(d) plan options is discussed in sections VII and VIII of the preamble. 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 Legal Memorandum for the CPP Final Rule, the GHG Mitigation Measures TSD for the CPP Final Rule, the CO 2 Emission Performance Rate and Goal Computation TSD for the CPP Final Rule, the Rate-based Program Accounting TSD for the CPP Final Rule, and the Response to Comments document, all of which

are available in the docket. A. The Best System of Emission Reduction*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 249 of 1275

This section sets forth our determination of the BSER for reducing CO 2 emissions from existing EGUs, including a discussion of the associated emissions performance level, and the rationale for that determination. In section V.A.1., we describe the legal framework for determination of the BSER in general. Section

V.A.2. summarizes the determination of the BSER for this rule. In section V.A.3., we discuss changes from the proposal. Section V.A.4. provides more detail on our determination of the BSER, including our determinations regarding the individual elements of the BSER, viewed from the perspective of the overall category

of affected sources. In section V.A.5. we discuss the BSER from a second perspective, comprising the range of actions thatindividual affected sources may take to achieve the EPAidentified performance levels that reflect the BSER and that form the basis for the standards of performance that states must set. In this discussion, we recognize that states can choose to set sources’ standards of performance in different forms and that the form of the standard affects how various types of actions can be used to comply with the standard. In section V.A.6. we discuss the substantial compliance flexibility provided by additional measures, not included in the BSER, that

individual affected sources can use to achieve their standards*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 250 of 1275 of performance. Finally, section V.A.7. addresses severability of the building blocks. 1. Legal requirements for BSER in the emission guidelines a. Introduction. In the June 2014 proposal for this rule, we described the principal legal requirement for standards of performance under CAA section 111(d)(1) and (a)(1). We based our description in part on our discussion of the legal requirements for standards of performance under CAA section 111(b) and (a)(1), which we included in the January 2014 proposal for standards of performance for CO 2 emissions from new fossil fuelfired EGUs. In the latter proposal, we noted that the D.C. Circuit has handed down numerous decisions that interpret CAA section 111(a)(1), including its component elements, and we

reviewed that case law in detail. 234 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. 235

234 79 FR 1430, 1462 (January 8, 2014). 235 We also discuss our interpretation of the requirements for standards of performance and the BSER under section 111(b), for new sources, in the section 111(b) rulemaking that the EPA is finalizing simultaneously with this rule. Our interpretations of these requirements in the two rules are generally consistent except to the extent that they reflect distinctions between new*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 251 of 1275 b. CAA requirements and court interpretation. Section 111(d)(1) directs the EPA to promulgate regulations establishing a section 110-like procedure under which states submit state plans that establish “standards of performance” for emissions of certain air pollutants from sources which, if they were new sources, would be regulated under section 111(b), and that implement and enforce those standards of performance. The term “standard of performance” is defined to mean— 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 and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. Section 111(a)(1). 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

and existing sources. For example, as discussed in the section 111(b) rule, the legislative history indicates that Congress intended that the BSER for new industrial facilities, which were expected to have lengthy useful lives, would include the most advanced pollution controls available, but Congress had a broader conception of the BSER for existing facilities.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 252 of 1275 CAA requirements, the EPA’s regulations require that the EPA’s guidelines reflect-- the degree of emission reduction achievable through the application of the best system of emission reduction which (taking into account the cost of such reduction) the Administrator has determined has been adequately demonstrated. 236 The EPA’s approach in this rulemaking is to determine the BSER on a source category-wide basis, to determine the emission limitation that results from applying the BSER to the sources, and then to establish emission guidelines that incorporate those emission limitations. The EPA expresses these emission limitations in the form of the performance levels, and they must be achievable by the source category. However, the state has broad discretion in applying the standards of performance to its sources. That is, for any particular source, a state may apply a standard of performance that is either more stringent or less stringent than the EPA’s performance level, as long as, in total, the state’s sources achieve at least the same degree of

emission limitation as included in the EPA’s emission

236 40 C.F.R. § 60.21(e). This definition was promulgated as part of the EPA’s CAA 111(d) implementing regulations and was not updated to reflect the textual changes adopted by Congress in 1977. That said, Congress recognized that those changes “merely make[] explicit what was implicit in the previous language.” H.R. Rep. No. 95-294, at 190 (May 12, 1977).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 253 of 1275 guidelines. 237 The states must include the standards of performance in their state plans and submit the plans to the EPA for review. 238 Section 111(d)(2) authorizes the EPA to approve state plans as long as they are “satisfactory.” Under the EPA’s regulations, state plans must include emission standards and compliance schedules for all “designated facilities” within the state, and may, “[o]n a case-by-case basis for particular designated facilities, or classes of facilities, ... provide for the application of less stringent emission standards or longer compliance schedules than those otherwise required” by the corresponding emission guideline. 239 This variance provision, promulgated in 1976, in conjunction with CAA section 111(d)’s “remaining useful life” provision, allows the states to vary the emission reduction obligations for their sources.

237 In addition, under CAA section 116, the state is authorized to set a standard of performance for any particular source that is more stringent than the BSER, and for all of its sources that is more stringent than the EPA’s performance level. Further, the state may consider remaining useful life and other factors in applying a standard of performance to a source, as discussed below. 238 40 C.F.R. § 60.23. 239 40 C.F.R. § 60.24(f). Some of the factors that a state may consider for this case-by-case analysis include the “cost of control resulting from plant age, location, or basic process design” and the “physical impossibility of installing necessary control equipment,” among other factors “that make application of a less stringent standard or final compliance time significantly more reasonable.” Id.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 254 of 1275 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. 240 In addition, although the D.C.

240 In the 1970 CAAA, Congress defined “standard of performance,” under §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 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 255 of 1275 Circuit has never reviewed a section 111(d) rulemaking, the Court has reviewed section 111(b) rulemakings on numerous occasions during the past 40 years, handing down decisions dated from 1973 to 2011, 241 through which the Court has developed a body of case law that interprets the term “standard of performance.” c. Key elements of interpretation. The emission guidelines promulgated by the Administrator must include emission limitations that are “achievable” by the source category 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

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 in the case law remain relevant to the definition as it reads today. 241 Portland Cement Ass’n v. Ruckelshaus , 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, (D.C. Cir. 1973); Portland Cement Ass’n v. EPA , 665 F.3d 177 (D.C. Cir. 2011). See also Delaware v. EPA , No. 13-1093 (D.C. Cir. May 1, 2015).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 256 of 1275 also take into account “the amount of air pollution” 242 reduced and the role of “technological innovation.” 243 Before turning to each of these elements below, we discuss our overall approach to determining the BSER and emission guidelines more generally. 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 emission reduction systems that have been “adequately demonstrated” for a particular source category. Second, we determine the best of these systems after evaluating costs, any nonair health and environmental impacts, and energy requirements. And third, we select an achievable emission limit –- here, the emission performance standard -- based on the BSER. (1) Achievability of the emission limitation in the emission guidelines. 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. For existing sources, section 111(d)(1) requires the EPA to establish requirements for state plans that

242 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 243 See Sierra Club v. Costle, 657 F.2d at 347.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 257 of 1275 must include “standards of performance.” Through long-standing regulations 244 and consistent practice, the EPA has interpreted this provision to require the EPA to promulgate emission guidelines that determine the BSER for a source category and that identify the amount of emission limitation achievable by application of the BSER. Although section 111(d)(1) and (a)(1) are not explicit on whether the emission limitation must be achievable by each source in the source category, the EPA has promulgated these emission guidelines on the basis that each source can achieve the limitation, even though the State retains discretion to apply standards of performance to individual sources that are more or less stringent. By comparison, in a rulemaking for new sources under section 111(b), the EPA must promulgate the “standards of performance” directly, and the first element of the definition of “standard of performance” is that the emission

limitation reflected in the “standard for emissions” that the EPA promulgates must be “achievable” based on application of the BSER. 79 FR 1430, 1463 (January 8, 2014). Moreover, again, for new sources, a standard of performance is “achievable” if a technology can reasonably be projected to be available to an

244 40 C.F.R. § 60.21(e).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 258 of 1275

individual source at the time it is constructed that will allow

it to meet the standard. 245 In this rulemaking, we are taking the same approach for the emission limitation that the EPA identifies in the emission guidelines. According to the D.C. Circuit, ”[a]n achievable standard is one which is within the realm of the adequately demonstrated system’s efficiency and which, while not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption.” 246 To be achievable, a standard “must be capable of being met under most adverse conditions which can be reasonably be expected to

recur and which are not or cannot be taken into account in determining the ‘cost of compliance.’” 247 To show a standard is achievable, the EPA must “(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry-wide performance, given the range of variables that affect the achievability of the

245 246 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433-34 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 247 Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 433, n.46 (D.C. Cir. 1980).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 259 of 1275

standard.” 248 (2) System of emission reduction. 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 working together as parts of a mechanism or interconnecting network; a complex whole.” 249 With this definition, the phrase “system of emission reduction” takes a broad meaning: a set of things that work together to reduce emissions. The EPA interprets this phrase to carry an important limitation: Because the emission guidelines for the existing sources must reflect “the degree of emission limitation achievable through the application of the best system of emission reduction ... adequately demonstrated,” the system must be limited to things that can be implemented – “appl[ied]” -- by the sources themselves, that is, as a practical matter, by actions taken by

248 Sierra Club v. Costle , 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l Lime Ass’n v. EPA , 627 F.2d 416 (D.C. Cir. 1980). In considering the representativeness of the source tested, the EPA may consider such variables as the “‘feedstock, operation, size and age’ of the source.” Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to “generalize from a sample of one when one is the only available sample, or when that one is shown to be representative of the regulated industry along relevant parameters.” Nat’l Lime Ass’n v. EPA , 627 F.2d 416, 434, n.52 (D.C. Cir. 1980). 249

Oxford Dictionary of English (3rd ed.) (published 2010, online version 2013) http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/ 9780199571123.001.0001/acref-9780199571123.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 260 of 1275 the owners or operators of the sources. As we discuss below, this definition is sufficiently broad to include the building

blocks. (3) Technical feasibility of the best system of emission reduction. 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. See 79 FR 1430, 1463 (January 8, 2014). (4) Amount of emissions reductions. 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. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no sensible interpretation of the statutory words “best ... system” which would not incorporate the amount of air pollution as a relevant factor to be weighed when determining the optimal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 261 of 1275 standard for controlling ... emissions”). 250 The fact that the purpose of a “system of emission reduction” is to reduce emissions, and that the term itself explicitly incorporates the concept of reducing emissions, supports the Court’s view that in determining whether a “system of emission reduction” is the “best,” the EPA must consider the amount of emission reductions that the system would yield. Even if the EPA were not required to consider the amount of emission reductions, the EPA has the discretion to do so, on grounds that either the term “system of emission reduction” or the term “best” may reasonably be read

under Chevron step 2 to allow that discretion. (5) Costs. 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, 251 in several cases the D.C. Circuit has elaborated on

this cost factor and formulated the cost standard in various ways, stating that the EPA may not adopt a standard the cost of

250 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA version of the definition of “standard of performance,” which revised the phrase “best system” to read, “best technological system.” As noted above, the 1990 CAAA deleted “technological,” and thereby returned the phrase to how it read under the 1970 CAAA. The court’s interpretation of this phrase in Sierra Club v. Costle to require consideration of the amount of air emissions remains valid for the phrase “best system.” 251 79 FR 1430, 1464 (January 8, 2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 262 of 1275 which would be “exorbitant,” 252 “greater than the industry could bear and survive,” 253 “excessive,” 254 or “unreasonable.” 255 These formulations appear to be synonymous, and for convenience, in this rulemaking, we will use reasonableness as the standard, so that a control technology may be considered the “best system of emission reduction ... adequately demonstrated” if its costs are reasonable, but cannot be considered the best system if its

costs are unreasonable. 256

252 Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999). 253 Portland Cement Ass’n v. EPA , 513 F.2d 506, 508 (D.C. Cir. 1975). 254 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981). 255 Sierra Club v. Costle , 657 F.2d 298, 343 (D.C. Cir. 1981). 256 These cost formulations are consistent with the legislative history of section 111. The 1977 House Committee Report noted: In the [1970] Congress [sic: Congress’s] view, it was only right 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. 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 263 of 1275

The D.C. Circuit has never invalidated a standard of performance on grounds that it was too costly. 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.” 257 See Essex Chemical Corp. v. Ruckelshaus , 486 F.2d 427, 440 (D.C. Cir. 1973); 258 Portland Cement Association v.

Ruckelshaus , 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club

v. Costle , 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding standard imposing controls on SO 2 emissions from coal-fired power plants when the “cost of the new controls ... is substantial”). 259 As discussed below, the EPA may consider costs on both a source-specific basis and a sector-wide, regional, or nationwide

S. Comm. Rep. No. 91-1196 at 16. 257 1977 House Committee Report at 184. 258 The costs for these standards were described in the rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 (March 21, 1972). 259 Indeed, in upholding the EPA’s consideration of costs under other provisions requiring consideration of cost, courts have also noted the substantial discretion delegated to the EPA to weigh cost considerations with other factors. Chemical Mfr’s Ass’n v. EPA , 870 F. 2d 177, 251 (5th Cir. 1989); Association of Iron and Steel Inst. v. EPA , 526 F. 2d 1027, 1054 (3d Cir. 1975); Ass’n of Pacific Fisheries v. EPA, 615 F. 2d 794, 808 (9th Cir. 1980).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 264 of 1275

basis. (6) Non-air health and environmental impacts. 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 and whether it is adequately demonstrated. This requirement makes explicit what was implicit in the initial version of section 111: a system cannot be “best” if it does more harm than good due to cross-media environmental impacts. 260 (7) Energy considerations. 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. (8) Sector- or nationwide component of factors in determining the BSER. 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

260 Portland Cement v. EPA , 486 F. 2d at 384; Sierra Club v. Costle , 657 F. 2d at 331; see also Essex Chemical Corp. v. Ruckelshaus , 486 F. 2d at 439 (remanding standard to consider solid waste disposal implications of the BSER determination).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 265 of 1275 time, and not only on a plant-specific level at the time of the rulemaking. 261 The D.C. Circuit based this conclusion on a review of the legislative history, stating, 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. 262

The Court has upheld EPA 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 2 emissions (3 million tons in 1995) yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting the development of less expensive SO 2 control technology, the final standard will expand environmentally acceptable energy supplies to existing power plants and industrial sources. By substantially reducing SO 2 emissions, the standard will enhance the potential for long term economic growth at both the national and regional levels. 263

261 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. Costle , 657 F.2d at 351). 262 Sierra Club v. Costle , 657 F.2d at 331 (citations omitted) (citing legislative history). 263 Sierra Club v. Costle , 657 F.2d at 327-28 (quoting 44 Fed. Reg. at 33,583/3 - 33,584/1). In the January 2014 proposal, we explained that although the D.C. Circuit decided Sierra Club v.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 266 of 1275

As with the final rule under section 111(b) that is associated with this rule, the EPA is considering costs andenergy implications on the basis of both their sourcespecific impacts and a sector-wide, regional, or national

basis. (9) “Adequately demonstrated.” Under section 111(a)(1), in order for a system of emission reduction to qualify as the

“best” and 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.” 264 It does not mean that the system “must be

in actual routine use somewhere.” 265 Rather, the court has said, “[t]he Administrator may make a projection based on existing

Costle before the Chevron case was decided in 1984, the D.C. Circuit’s decision could be justified under either Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 2014). 264 Essex Chem. Corp. v. Ruckelshaus , 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied , 416 U.S. 969 (1974). 265 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted) (discussing the Senate and House bills and reports from which the language in CAA section 111 grew).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 267 of 1275 technology, though that projection is subject to the restraints of reasonableness and cannot be based on ‘crystal ball’ inquiry.” 266 Similarly, the EPA may “hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are

feasible.” 267 Ultimately, the analysis “is partially dependent on ‘lead time,’” that is, “the time in which the technology will

have to be available.” 268 Unlike for CAA section 111(b) standards that are immediately applicable, compliance with CAA section 111(d) standards may be set sometime in the future.

(10) Expanded use and development of technology. 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.” See Sierra Club v. Costle , 657 F.2d at 346-47. The Court has grounded its reading in the statutory text. 269 In

266 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 267 Sierra Club v. Costle , 657 F.2d 298, 364 (1981). 268 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations omitted). 269 Sierra Club v. Costle , 657 F. 2d at 346 (“Our interpretation of section 111(a) is that the mandated balancing of cost,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 268 of 1275 addition, the Court’s interpretation finds firm support in the legislative history. 270 The legislative history identifies 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 section 111(a)(1); 271 (ii) the expanded use of the best demonstrated technology; 272 and (iii) the development of emerging technology. 273 Even if the EPA were not required to consider technological innovation as part of its

energy, and nonair quality health and environmental factors embraces consideration of technological innovation as part of that balance. The statutory factors which EPA must weigh are broadly defined and include within their ambit subfactors such as technological innovation.”). 270 See S. Rep. 91-1196 at 16 (1970) (“Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources”); S. Rep. 95-127 at 17 (1977) (cited in Sierra Club v. Costle , 657 F.2d at 346 n. 174) (“The section 111 Standards of Performance ... sought to assure the use of available technology and to stimulate the development of new technology”). 271 See Portland Cement Ass’n v.Ruckelshaus , 486 F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduction must “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at present”). 272 See 1970 Senate Committee Report No. 91-1196 at 15 (“The maximum use of available means of preventing and controlling air pollution is essential to the elimination of new pollution problems”). 273 See Sierra Club v. Costle , 657 F.2d at 351 (upholding a standard of performance designed to promote the use of an emerging technology).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 269 of 1275 determination of the BSER, it would be reasonable for the EPA to consider it, either because technological innovation may be considered an element of the term “best,” or because the term “best system of emission reduction” is ambiguous as to whether technological innovation may be considered, and it is reasonable for the EPA to interpret it to authorize consideration of technological innovation in light of Congress’s emphasis on technological innovation. 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. (11) Agency discretion. 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 Sierra Club v. Costle , 657 F.2d 298 (D.C. Cir. 1981), the Court explained that “section 111(a) explicitly instructs the EPA to balance multiple concerns when promulgating a NSPS,” 274 and emphasized that “[t]he text gives the EPA broad discretion to weigh different factors in

274 Sierra Club v. Costle , 657 F.2d at 319.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 270 of 1275 setting the standard.” 275 In Lignite Energy Council v. EPA , 198 F.3d 930 (D.C. Cir. 1999), the Court reiterated: 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. 276

d. Approach to the source category and subcategorizing. Section 111 requires the EPA first to list source categories that may reasonably be expected to endanger public health or welfare and then to regulate new sources within each such source category. Section 111(b)(2) grants the EPA discretion whether to “distinguish among classes, types, and sizes within categories

275 Sierra Club v. Costle , 657 F.2d at 321; see also New York v. Reilly , 969 F. 2d at 1150 (because Congress did not assign the specific weight the Administrator should assign to the statutory elements, “the Administrator is free to exercise [her] discretion” in promulgating an NSPS). 276

Lignite Energy Council v. EPA , 198 F.3d 930, 933 (D.C. Cir. 1999) (paragraphing revised for convenience). See New York v. Reilly , 969 F.2d 1147, 1150 (D.C. Cir. 1992) (“Because Congress did not assign the specific weight the Administrator should accord each of these factors, the Administrator is free to exercise his discretion in this area.”); see also NRDC v. EPA , 25 F.3d 1063, 1071 (D.C. Cir. 1994) (EPA did not err in its final balancing because “neither RCRA nor EPA’s regulations purports to assign any particular weight to the factors listed in subsection (a)(3). That being the case, the Administrator was free to emphasize or deemphasize particular factors, constrained only by the requirements of reasoned agency decisionmaking.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 271 of 1275 of new sources for the purpose of establishing [new source] standards,” which we refer to as “subcategorizing.” Section 111(d)(1), in conjunction with section 111(a)(1), simply requires the EPA to determine the BSER, does not prescribe the method for doing so, and is silent as to whether the EPA may subcategorize. The EPA interprets this provision to authorize the EPA discretion as to whether and, if so, how to subcategorize. In addition, the regulations under CAA section 111(d) provide -- The Administrator will specify different emission guidelines or compliance times or both for different sizes, types, and classes of designated facilities when costs of the control, physical limitations, geographical location, or similar factors make subcategorization appropriate. 277

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 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,

277 40 CFR 60.22(b)(5).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 272 of 1275 as long as the overall level of emission limitation is at least as stringent as the emission guidelines.

2. The BSER for this Rule – Overview a. Summary. This section describes the EPA’s overall approach to establishing the BSER. This rule, promulgated under CAA section 111(d), establishes emission guidelines, and the BSER is the central determination that the EPA must make in doing so. In understanding the EPA’s basis for the BSER, it is useful to view the BSER from two complementary perspectives. The first perspective considers the subcategory of the steam affected EGUs as a whole, and the subcategory of the combustion turbine affected EGUs as a whole, treats the BSER for each subcategory as the measures identified by the EPA that the sources, viewed together, can implement to reduce their emissions to an appropriate amount, and that meet the other requirements for the BSER including, for example, cost reasonableness. For convenience, this may be referred to as the source-category perspective because it views the BSER on a category- or subcategory-wide basis. After identifying the BSER in this manner, the EPA determines the performance levels –- in this case, the CO 2 emission performance rates –- for the steam generators and for the combustion turbines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 273 of 1275 The second perspective considers the affected EGUs individually, and treats the BSER as the set of actions that an EGU 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. For convenience, this may be referred to as the individual-source perspective. Under either perspective, the EPA determines the BSER as encompassing the same set of actions, but the two perspectives serve to elucidate the EPA’s reasoning.

Anexample illustrating the relationship between the sourcecategory and individual-source perspectives for this rule is the substitution of non-emitting generation for CO 2 -emitting generation. This measure involves two distinct actions: increasing the amount of non-emitting generation and reducing

the amount of CO 2 -emitting generation. From the source-category perspective, the two actions are halves of a single balanced endeavor, but from the individual-source perspective, the two actions are separable, and a particular affected EGU may decide to implement either or both of the actions. Further, an individual source may choose to invest directly in actions at*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 274 of 1275 its own facility or an affiliated facility or to cross-invest in actions at other facilities on the interconnected electricity system.

To reiterate the overall context for the BSER: In this rule, the EPA determined the BSER, and applied it to the category of affected sources to determine the performance levels –- that is, the CO 2 emission performance rates -- for steam generators and for combustion turbines. States must impose emission limits on their sources that, in total, achieve the same emissions performance level that the CO 2 emission performance rates would achieve if applied directly to each

source as the standard or emissions limitation it must meet. Each state has flexibility in how it assigns the emission limitations to its affected EGUs –- and in fact, the state can be more stringent than the guidelines require –- but one of the state’s choices is to assign the CO 2 emission performance rates or the mass equivalents thereof to each of its affected EGUs. If a state does so, then the affected EGUs may achieve their emission limits by taking the actions that qualify as the BSER. Since the BSER and, in this case its constituent elements, reflect the critical criteria of feasibility, reasonable cost, and other BSER criteria, the BSER assures that there is at least one pathway –- the CO 2 emission performance rates or mass*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 275 of 1275 equivalents -- for the state and its affected EGUs to take that achieves the requisite level of emission reductions, while, again, assuring that the affected EGUs can achieve those

emission limits at reasonable cost and consistent with the other

factors for the BSER. This section describes the EPA’s process and basis for determining the BSER for the purpose of determining the CO 2 emission performance rates. 278 As noted above, the BSER determined through this process can be described from two perspectives. Viewed from the source-category perspective, the EPA is identifying the BSER as a well-established set of measures that EGUs have used for many years to achieve various business and policy purposes, and have used in recent years for the specific purpose of reducing their CO 2 emissions, and that are appropriate to the global nature of carbon pollution and afforded by the highly integrated nature of the utility power sector. These measures include (i) increasing the operational efficiency of existing coal-fired steam EGUs on average by a specified percentage (building block 1); (ii) substituting increased generation from existing NGCC units for reduced generation at existing steam EGUs in specified amounts (building

278 Other sections in this preamble describe how EPA calculated the CO 2 emission performance rates based on the BSER.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 276 of 1275 block 2); and (iii) substituting increased generation from new zero-carbon generating capacity for reduced generation at existing fossil fuel-fired EGUs in specified amounts (building block 3). It should be noted that building block 2 incorporates reduced generation from steam EGUs on a source category-wide basis and building block 3 incorporates reduced generation from all fossil fuel-fired EGUs on a source category-wide basis. Further, as discussed below, given the global nature of carbon pollution and the highly integrated utility power sector, each of the building blocks incorporates various mechanisms for facilitating cross-investment by individual affected EGUs in emission rate improvements or emission reduction activities at other location on the interconnected electricity system. The range of mechanisms includes bilateral investment of various kinds, the issuance and purchase of emission rate credits representing the emissions-reducing effects of specific activities, more general emissions trading using rate-based credits or mass-based allowances, and other multi-unit compliance approaches such as averaging or bubbling. 279 Viewed from the individual-source perspective, the EPA is identifying the BSER as a menu of actions -- all of which fall

279 Conditions for the use of these mechanisms under various state plans are discussed in section VIII.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 277 of 1275

within the set of measures identified as the BSER from the source-category perspective -- 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 coal-fired 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 affectedEGUs can implement to increase generation from new low- or zerocarbon generation sources in specified amounts, (iv) all affected EGUs can implement to reduce their generation in specified amounts, and (v) all affected EGUs can implement by means of purchasing rate-based emission credits or mass-based emission allowances from other affected EGUs through trading, since the effect of the purchase would be the same as achieving the other listed actions through direct means, and (vi) all affected EGUs can implement through other multi-unit compliance approaches such as averaging or bubbling. 280 Importantly, viewed from either the source-category perspective or the individual-source perspective, affected EGUs

also have available numerous other measures that are not

280 Again, conditions for the use of these mechanisms under various state plans are discussed in section VIII.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 278 of 1275 included in the BSER but that could materially help the EGUs achieve their emission limits and thereby provide compliance flexibility. Examples include investment in demand-side energy efficiency, 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. The EPA’s review of measures for determining the BSER. The EPA described in the proposal for this rule the analytical process by which the EPA determined the BSER for this source category. The EPA is finalizing large parts of that analysis, but the EPA is also refining that analysis based on comments and

further evaluation. What follows is the EPA’s final

determination. As described in the proposal, to determine the BSER, the EPA began by considering the characteristics of CO 2 pollution and the utility power sector. The characteristics of CO 2 pollution are discussed at length in the proposed rule and in section II above. The salient facts include the pollutant’s global nature, which makes the specific location of emission reductions unimportant; the need to make large reductions in order to protect human health and the environment; and fact that the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 279 of 1275 utility power sector is the single largest source category by a considerable margin. The characteristics of the utility power sector are also discussed at length in the proposal and in section II above. 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 auniquely high degree of coordination in both planning and realtime 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.” 281 The core function of providing reliable electricity service is carried out not by individual electricity generating units but by the complex machine as a whole. Important subsidiary functions such as management of costs and management

281 S. Massoud Amin, Securing the Electricity Grid, 40 The Bridge 1, 14 (2010); Phillip F. Schewe, The Grid: A Journey Through the Heart of Our Electrified World 1 (2007).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 280 of 1275 of environmental impacts are also carried out to a great extent

on a multi-unit basis rather than an individual-unit basis. Generation from one generating unit can be and routinely is substituted for generation from another generating unit in order to keep the complex machine operating while observing the machine’s technical, environmental, and other constraints and managing its costs. The EPA also reviewed broad trends within the utility power sector. It is evident that, in the recent past, coal-fired electricity generation has been reduced, and projected futuretrends are for continued reduction. By the same token, loweremitting NGCC generation and renewable generation have increased, and projected future trends are for continued

increases. 282 A survey of integrated resource plans (IRPs), included in the docket, shows that fossil fuel-fired EGUs have are taking actions to reduce emissions of both non-GHG air pollutants and GHGs. 283 Some fossil fuel-fired EGUs are investing in lower- or zero-emitting generation. In fact, our review indicates that the great majority of fossil fuel-fired generators surveyed are including new renewable energy resources

282 Demand-side energy efficiency measures have also increased, and the projected future trends are for continued increase. 283 The IRPs typically also indicate planned investment in demand-side energy efficiency.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 281 of 1275 in their planning. In addition, some fossil fuel-fired EGUs are using those measures to replace their higher-emitting generation. Some fossil fuel-fired generators appear to be reducing their higher-emitting generation without fully replacing it. These measures in aggregate result in thereplacement of higher-emitting generation with lower- or zeroemitting generation, reflecting the integrated nature of the electricity system. The EPA examined state and company programs intended at least in part to reduce CO 2 from fossil fuel-fired power plants. These programs include GHG performance standards established by states including California, New York, Oregon, and Washington; utility planning approaches carried out by companies in Colorado and Minnesota; and renewable portfolio standards (RPS)

established in more than 25 states. 284 They also include marketbased initiatives, such as the Regional Greenhouse Gas Initiative (RGGI) and the GHG emissions trading program established by the California Global Warming Solutions Act. We also examined federal legislative and regulatory programs, as well as state programs currently in operation that address pollutants other than CO 2 emitted by the power sector. These programs include, among others, the CAA Title IV program

284 See 79 FR 34848-34850.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 282 of 1275

to reduce SO 2 and NO X , the MATS program to reduce mercury and air toxic emissions, and the CSAPR program to reduce SO 2 and NO X . 285 This analysis demonstrated that, among other measures, the application of control technology, fuel-switching, and improvements in the operational efficiency of EGUs all resulted in reductions in a range of pollutants. These programs also demonstrate that replacement of higher-emitting generation with lower-emitting generation -- including generation shifts between coal-fired EGUs and natural gas-fired EGUs –- and zero-emitting generation such as renewable energy, also reduce emissions. Some of these programs also include emissions trading among the power plants. In this rule, when evaluating the types and amounts of measures that the source category can take to reduce CO 2 emissions, we have appropriately taken into account the global nature of the pollutant and the high degree to which each individual affected EGU is integrated into a “complex machine” that makes it possible for generation from one generating unit to be replaced with generation from another generating unit for the purpose of reducing generation from CO 2 –emitting generating units. We have also taken into account the trends away from higher-carbon generation toward lower- and zero-carbon

285 Many of these programs are discussed in section V.B.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 283 of 1275 generation. These factors strongly support consideration of emission reduction approaches that focus on the machine as a whole –- that is, the overall source category –- by shifting generation from dirtier to cleaner sources in addition to emission reduction approaches that focus on improving the

emission rates of individual sources. 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 and other multi-unit compliance 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 or other multi-unit compliance approaches to achieve the standards of performance established in those plans, and we believe it is highly likely 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 284 of 1275 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.” These multi-unit mechanisms are an inherent aspect of the way in which the machine is managed to address constraints at the source-category level, and they can therefore be considered an inherent aspect of emission reduction measures available at the source-category level to address a global pollutant such as CO 2 . Although the choice of which particular multi-unit compliance mechanisms to allow is a matter to be determined primarily by the states in carrying out their obligations to set standards of performance through their*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 285 of 1275 section 111(d) plans, a plan that did not allow the use of any such mechanisms would be so contrary to the integrated nature of the industry and so disadvantageous to a state’s own individual sources that we, again, view any such plan as extremely unlikely and not a possibility that we would be obligated to view as constraining the appropriate analysis of the BSER. Further reinforcing our conclusion that such an outcome is unlikely is the extensive interest in using such mechanisms that states and utilities demonstrated through their formal comments and in discussions during the outreach process.

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 global nature of CO 2 pollution and the unique, interconnected nature of the electricity sector make certain types of measures and mechanisms available and appropriate for consideration as the BSER for this rule that would not be appropriate for other pollutants and other industrial sectors. For purposes of this discussion, the measures can be categorized in terms of the essential characteristics of the four building blocks described in the proposal: Measures that (i) reduce the CO 2 emission rateat the unit, (ii) substitute generation from existing loweremitting fossil fuel-fired units for generation from higher-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 286 of 1275 emitting fossil fuel-fired units, (iii) substitute generation from new low- or zero-emitting generating capacity, especially renewable energy, for generation from fossil fuel-fired units, and (iv) increase demand-side energy efficiency to avoid generation from fossil fuel-fired units. In the proposal, we

described our evaluations of various measures in each of these categories. In this rule, with the benefit of comments, we have refined our evaluation of which specific measures should comprise the first three building blocks, and, for reasons discussed below, we have determined that the fourth building block, demand-side energy efficiency, should not be included in

the BSER. The measures are discussed more fully below, but it should be noted here that because of the integrated nature of the utility power sector, coupled with the sector’s high degree of planning and reliability safeguards, the measures in the secondand third categories, which involve generation shifts to lowerand zero-emitting sources, may occur in several different ways from the individual-source perspective, all of which are equivalent from the source-category perspective. First, a higher-emitting fossil unit may invest in cleaner generation without reducing its own generation, which would result in less demand for, and therefore reductions in generation by, other*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 287 of 1275 higher-emitting units. Second, a higher-emitting fossil unit may reduce its generation, which, in the presence of requirements for the source category as a whole to reduce CO 2 emissions, would result in increased demand for, and therefore increased amounts of, cleaner generation. Third, a higher-emitting fossil unit may do both of these things, directly replacing part of its generation with investments in lower- or zero-emitting generation. 286 In addition, for measures in all of the categories, multiple mechanisms exist by which an individual affected source may make these investments, ranging from bilateral investments, to purchase of credits representing the emissions-reducing benefits of specific activities, to purchase of general rate-based emissions credits or mass-based emission allowances, to other multi-unit compliance approaches such as averaging or bubbling. c. State establishment of standards of performance and source compliance. Before identifying in detail the measures that the BSER comprises, it is useful to describe the process by which the states establish the standards of performance with which the affected EGUs must comply, and the implications of the sources’ need to comply for identifying the BSER. As part of the EPA’s emission guidelines in this rule, and based on the BSER, the EPA

286 The same is true for demand-side energy efficiency measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 288 of 1275 is identifying CO 2 emission performance rates and, for purposes of facilitating states’ efforts to formulate compliance plans encompassing maximum flexibilities, aggregating them into goals for each state. As discussed below, a state, in turn, is charged with setting specific standards of performance for its EGUs such that the emission limitations from the EGUs operating under those standards of performance together meet the performance rates or the state goal. To do this, the state must adopt a plan that establishes the EGUs’ standards of performance and that implements and enforces those standards. A state has significant flexibility in several respects. For example, a state may impose standards of performance on its

steam EGU sources and on its combustion turbine sources representing the respective CO 2 emission performance rates for those subcategories set in the emission guidelines. Alternatively, a state may impose standards with differing degrees of stringency on various sources, and, in fact, may be more stringent overall than its state goal requires. In addition –- and most importantly for purposes of describing the BSER -- a state may set standards of performance either as emission rates (e.g., lbs of CO 2 per MWh) or mass limits (e.g., tons of CO 2 per year). Under a mass limit approach, each affected EGU must

retire an allowance for each ton of CO 2 emitted. M oreover, a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 289 of 1275state may make those limits tradable or authorize other multiunit compliance mechanisms (subject to conditions described in section VIII below). The form of the emission limits, whether emission rate limits or mass limits, has implications for what specific actions the individual affected EGUs may take to achieve those limits –- that is, the measures that comprise the BSER from the individual-source perspective –- as well as what specific non-BSER measures are available to the individual affected EGUs for compliance flexibility. For example, if an individual source chooses to adopt building block 3 by both investing in lower- or zero-emitting generation and reducing its own generation, both those actions will be accounted for in its emission rate and both will therefore help the source meet its

rate-based limit. If the same individual source takes the same actions but is subject to a mass-based limit, the action of reducing its generation will directly count in helping the source meet its own mass-based limit but the action of investing in cleaner generation will not. However, the investment in lower-or zero-emitting generation by that source and other sources collectively will help the overall source category

achieve the emission limits consistent with the BSER and in doing so will make it easier for that source and other sources collectively to meet their mass-based limits.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 290 of 1275 d. Identification of the BSER measures – the source-category perspective. We first discuss the evaluation of potential measures for inclusion in the BSER from the source-category perspective. (1) Measures that reduce individual affected EGUs’ CO 2 emission rates. As described in the proposal, the measures that the affected EGUs could implement to improve their CO 2 emission

rates included a set of measures that the EPA determined would result in improvements in heat rate at coal-fired steam EGUs in the amount of 6 percent on average, and the EPA proposed that this set of measures qualifies as a component of the BSER. As described below, in this rule, the EPA concludes that those measures do qualify as a component of the BSER, although, based on comments and further evaluation, the EPA is narrowing the set of these types of measures that qualify as a component of the BSER and has quantified the emission reductions achievable through application of the measures on a regional basis, consistent with the treatment of the other building blocks in this final rule, rather than the nationwide basis used for building block 1 in the proposed rule. As a result of these refinements, the EPA is reducing the amount of emission reductions achievable on average from heat rate improvement measures at coal-fired steam EGUs to 4.3 percent for the Eastern*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 291 of 1275 Interconnection, 2.1 percent for the Western Interconnection, and 2.3 percent for the Texas Interconnection. 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 2 the source emits per MWh. As a result, these measures would help the source achieve an emission limit expressed as either an emission rate limit or as a mass limit. We note again that in the context both of the integrated electricity system and of anticipated state approaches to setting standards of performance, emissions trading or other multi-unit compliance approaches could be used as mechanisms through which one affected source could invest in heat rate improvements at another source. We discuss this aspect below in describing the individual-source perspective of the

BSER. These heat rate improvements are a low-cost option that fit the criteria for the BSER, but alone, they lead to only small emission reductions for the source category. Given the magnitude of the environmental problem and projections by climate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 292 of 1275 scientists that much larger emission reductions are needed from fossil fuel-fired EGUs to address climate change, the EPA looked

at additional measures to reduce emission rates. This reflects

our conclusion that emission reductions limited to this set of

measures would not meet one of the considerations critical to the BSER determination –- the quantity of emissions reductions resulting from the application of the BSER to 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. 287 The EPA also considered implementation of carbon capture and storage (CCS). 288 The EPA found that some of these co-firing and CCS measures are technically feasible and within price ranges that the EPA has found to be cost effective in the context of other GHG rules, that a segment of the source category may implement these measures, and that the resulting emission reductions could be potentially significant.

287 The EPA further addressed co-firing in the NODA. 79 FR 64549- 51. 288 CCS is also sometimes referred to as carbon capture and sequestration.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 293 of 1275 However, these co-firing and CCS measures are more expensive than other available measures. This is because the integrated nature of the electricity system affords significantly lower cost options, ones that fossil fuel-fired power plants throughout the United States and in foreign nations are already using to reduce their CO 2 . 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 renewable energy generating units. 289 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

289 Similarly, demand-side energy efficiency measures are lowcost measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 294 of 1275 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. 290

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 2 from affected EGUs at levels

that are commensurate with the sector’s contribution to GHG emissions and thus necessary to mitigate the dangers presented by climate change, could depend in part, but not primarily, on measures that improve efficiency at the power plants. Rather,

most of the CO 2 controls need to come in the form of those other measures that are available to the utility power sector thanks specifically to the integrated nature of the electricity system, and that involve, in one form or another, replacement of higher emitting generation with lower- or zero-emitting generation.

290 Many EGUs would also rely on demand-side energy efficiency measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 295 of 1275 Although the presence of lower-cost options that achieve the emission reduction goals mean 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). The EPA further discusses the potential use of these non-BSER measures for compliance flexibility below. Other measures to reduce emissions that some sources may implement, but that the EPA is not identifying as part of the BSER for various reasons,and that are also further discussed below, include biomass cofiring and conversion of an affected EGU’s waste heat to useful thermal energy. The EPA’s quantification of the CO 2 emission reductions achievable through heat rate improvements as a component of the BSER (building block 1) is discussed in section V.C. of this preamble and in the GHG Mitigation Measures TSD for the CPP

Final Rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 296 of 1275 (2) Measures available because of the integrated electricity system. To achieve the needed emission reductions, the EPA turned next to the set of measures that presented themselves as a result of the integrated nature of the electricity system. Those are the measures in the categories represented in the proposal by building blocks 2, 3, and 4. This section discusses the components of the BSER that relate to building blocks 2 and 3, which the EPA is finalizing as components of the BSER. This section also discusses the measures comprising the proposed building block 4, which the EPA is not including in the BSER in this final rule. It bears reiterating that the integrated nature of the 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 reliabilityassurance and cost reduction. In analyzing BSER from a sourcecategory perspective, because the affected EGUs are connected to each other operationally, a combination of dispatching and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 297 of 1275 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, emissions trading or other multi-unit compliance mechanisms may be used as mechanisms for implementing these building blocks. We discuss these aspects below in describing the individual-source perspective of the BSER. (a) Substituting generation from lower-emitting affected EGUs for reduced generation from higher-emitting affected EGUs (building block 2). In the proposal, the EPA observed that

substantial CO 2 emission reductions could be achieved at reasonable cost by increasing generation from existing NGCC units and commensurately reducing generation from steam EGUs. Because NGCC units produce much less CO 2 per MWh of generation than steam EGUs –- typically less than half as much CO 2 as coalfired steam EGUs, which account for most generation from steam EGUs –- this generation shift reduces CO 2 emissions. We also noted that because NGCC units can generate as much as 46 percent*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 298 of 1275 more electricity from a given quantity of natural gas than a steam unit can, generation shifting from coal-fired steam EGUs to existing NGCC units is a more cost-effective strategy for reducing CO 2 emissions from the source category than converting coal-fired steam EGUs to combust natural gas or co-firing coal and natural gas in steam EGUs. We proposed to find that shifting generation consistent with a 70 percent target utilization rate (based on nameplate capacity) for NGCC units was feasible and should be a component of the BSER. Further analysis reflecting consideration of the many comments we received on this issue supports the inclusion of generation shifting from higher-emitting to lower-emitting EGUs as a component of the BSER. Shifting of generation among EGUs is an everyday occurrence within the integrated utility power sector that is used to ensure that electricity is provided to

meet customer demands in the most economic manner consistent with system constraints. Generation shifting to lower-emitting units has been recognized as an approach for reducing emissions

in other EPA rules such as CSAPR. The EPA’s analysis continues to show that the magnitude of emission reductions included in the proposed rule from generation shifting is achievable. Some commenters stated that summer capacity ratings are a more appropriate basis upon which*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 299 of 1275 to compute a target utilization than nameplate capacity ratings used at proposal. 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) Substituting increased generation from new low- or zero-carbon generating capacity for reduced generation from affected EGUs (building block 3). Reducing generation from fossil fuel-fired EGUs and replacing it with generation from lower- or zero-emitting EGUs is another method for reducing CO 2 emissions from the utility power sector. In the proposal, the EPA identified renewable energy (RE) generating capacity andnuclear generating capacity as potential sources lower- or zeroCO 2 generation that could replace higher-CO 2 generation from

affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 300 of 1275 (i) Increased generation from new RE generating capacity. 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 2 emissions from the affected source category. Accordingly, we proposed to include replacement of defined quantities of fossil generation by RE generation in the BSER. With the benefit of comments, the EPA is finalizing the determination that substitution of RE generation from new RE generating capacity is a component of the BSER but 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 301 of 1275 the preamble and in the GHG Mitigation Measures TSD for the CPP

Final Rule. (ii) Increased and preserved generation from nuclear generating capacity. 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 2 emissions from the affected source category. We proposed to include two elements of nuclear generation in the BSER: an element representing projected generation from nuclear units under construction, and an element representing preserved generation from existing nuclear generating capacity at risk of

retirement. Like generation from new RE generating capacity, generation from new nuclear generating capacity can clearly replace fossil fuel-fired generation and thereby reduce CO 2 emissions. However,there are also important differences between these types of lowor zero-CO 2 generation. Investments in new nuclear capacity are very large, “lumpy,” capital-intensive investments and the building of nuclear facilities historically has been subject to delays and substantial risks of non-completion, both of which tend to raise costs. By comparison, investments in new RE generating capacity are relatively small and low-risk. Based on the small number of new nuclear generating projects, it is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 302 of 1275 difficult to ascertain a trend of increasing nuclear generation in the industry. These differences create greater uncertainty regarding the achievability and cost of generation from new nuclear capacity as a replacement for fossil fuel-fired generation, two important factors in determination of the BSER. Accordingly, as described in section V.A.3., the EPA is not finalizing increased generation from new nuclear capacity as a component of the BSER. 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 2 emissions from affected EGUs below current levels. Existing nuclear generation helps make existing CO 2 emissions lower than they would otherwise be, but will not further lower CO 2 emissions below current levels. Accordingly, as described in section V.A.3., the EPA is not finalizing preservation of generation from existing nuclear capacity as a component of the BSER. (c) Increasing demand-side energy efficiency to avoid generation and emissions from fossil fuel-fired EGUs. The final category of approaches for reducing generation and CO 2 emissions from affected EGUs that the EPA considered in the proposal involves increasing demand-side energy efficiency. When demand-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 303 of 1275 side energy efficiency is increased, energy consumers need lesselectricity in order to provide the same level of electricitydependent services – e.g., heating, cooling, lighting, and use of motors and electronic devices. Through the integrated electricity system, including the connection of customers to affected EGUs through the electricity grid, reduced demand for electricity, in turn, leads to reduced generation and reduced CO 2 emissions. Our examination of actions and trends underway in the utility power sector confirmed that demand-side energy programs are being implemented widely across the sector and that investments are increasing. We proposed to include avoidance of defined quantities of fossil fuel-fired generation through increased demand-side energy efficiency as a component of the BSER (proposed building block 4). Commenters expressed a wide range of views on the proposed reliance on demand-side energy efficiency 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 V.A.3.e. below, we are not finalizing the proposal to include avoided generation achieved through demand-side energy efficiency as a component of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 304 of 1275 BSER. However, we note that most commenters also supported the use of demand-side energy efficiency for compliance whether or not it is used in determining the BSER, and we are allowing demand-side energy efficiency to be used for that purpose. (3) Further analysis to quantify the BSER. 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 increases the achievability of the BSER for the source category and for individual sources. We note that a feature of the method by which we have quantified the degree of emission limitation achievable through application of the BSER to the two source subcategories -– namely, the use of the least stringent CO 2 emission performance rate quantified for a given source subcategory for any of the three major Interconnections as the

CO 2 emission performance rate for that source subcategory in all*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 305 of 1275

three Interconnections 291 –- provides additional headroom within

the BSER for sources in the two Interconnections that did not

set the CO 2 emission performance rates ultimately used. Additional headroom within the BSER is available through the use of emissions trading or other multi-unit compliance approaches,

because the final rule does not limit the use of these mechanisms to sources within the same Interconnections. In fact, in response to proposals that emerged from the comment record and direct engagement with states and stakeholders reflecting their strong interest in pursuing multi-state approaches, the guidelines include mechanisms for implementing standards of performance that foster interstate trading, as discussed in section VIII. (In addition, as further discussed below, the rule also permits section 111(d) plans to allow the use of non-BSER measures for compliance in certain circumstances, increasing both compliance flexibility and the assurance that the emission limitations reflecting application of the BSER are achievable.) Further, the sets of measures in each of these individual building blocks, in the stringency assigned in this rule, meet

291 Specifically, the respective CO 2 emission performance rates quantified for the steam EGU subcategory and for the stationary combustion turbine subcategory in the Eastern Interconnection are being applied to those subcategories in the Western and Texas Interconnections as well. This aspect of the BSER quantification methodology is discussed below in section V.A.3 and section VI.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 306 of 1275 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 affected EGUs and do not result in non-air quality pollutants, and have acceptable cost and energy implications for the energy sector as a whole. In addition, as explained below, each is adequately demonstrated. Importantly, past industry practice and current trends strongly support each of the building blocks, as do federal and state pollution control programs that require or result in similar

measures. 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 2 -emission control by states and companies. Moreover, Congress itself recognized in enacting the acid rain provisions of CAA Title IV that renewable energy measures reduce CO 2 from affected EGUs. In addition, the EPA has relied on the measures in building blocks 2 and 3 in other rules. It should also be noted that combinations of the building blocks also meet the criteria for the BSER, as described below.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 307 of 1275

e. Identification of the BSER measures – the individual-source perspective. We now turn to a summary of the evaluation of potential BSER measures from the individual-source perspective. (1) Improvement in CO 2 emission rate at the unit. An affected EGU may take steps to improve its CO 2 emission rate as discussed above under the source-category perspective. Although the only actions in this category identified for inclusion in the BSER are heat rate improvements at coal-fired steam EGUs, if a particular affected EGU found that its circumstances made some other actions in the category relatively attractive –- forexample, heat rate improvements at other types of EGUs, cofiring of natural gas, or retrofit of CCS –- the EGU could pursue those improvements. The resulting improvements in the

EGU’s CO 2 emission rate would help the EGU achieve an emission limit imposed in the form of an emission rate, and would also help the EGU achieve an emission limit imposed in the form of a mass limit if the EGU did not increase its generation by a larger percentage than the percentage of its emission rate improvement. (2) Actions to implement measures in building blocks 2 and 3. Viewing the BSER from the individual-source perspective, because of the integrated nature of the electricity system, coupled with the system’s high degree of planning and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 308 of 1275 reliability mechanisms, there are several ways that affected EGUs can access the measures in building blocks 2 and 3. 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 incentivizing 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. 292 (a) Investment in measures in building blocks 2 and 3. 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

292 These same methods are available for demand-side energy efficiency measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 309 of 1275 to increase generation, and purchase the CO 2 -reducing effects of that increased generation as emission rate credits. Similarly, for building block 3, an owner/operator of an affected EGU may build, or purchase an ownership interest in, new renewable energy generating capacity and purchase the CO 2 - reducing effects of that increased generation. Alternatively, an owner/operator may, through bilateral transactions, purchase the

CO 2 -reducing effects of that increased generation from renewable generation providers. 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 2 performance standard, the section 111(d) plan would need to provide –- and we expect that states would do so in their plans -- a mechanism by which the affected unit could account for the emissions-reducing benefit of the investment when computing its emission rate for purposes of determining compliance with the performance standard. The mechanism could involve use of an approved and validated instrument such as an “emission rate credit” representing the emissions-reducing benefit of the investment or could involve an approved averaging arrangement. 293

293 Criteria for issuance of valid emission rate credits and for tracking credits after issuance are discussed in section VIII below and in the Rate-based Program Accounting TSD for the CPP Final Rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 310 of 1275 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 source-category perspective. Therefore, the menu of these actions, including reduced generation, is appropriate for inclusion in the BSER. That is, if a state assigns to a source a standard of performance that is the same as the applicable CO 2 emission performance rate in the EPA emission guidelines, or the mass limit equivalent, the source could achieve the limit through implementation of the actions described above for building blocks 2 and 3, along with the actions described further above for building block 1. By the same token, for the demand-side energy measures that the EPA proposed as building block 4, an owner/operator of an affected EGU may implement demand-side energy efficiency programs directly or hire contractors or energy service companies to do so, and claim the resulting emission rate credits. The owner/operator may also engage in bilateral transactions with distribution utilities that already implement demand-side energy efficiency programs and pay them to implement*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 311 of 1275 such a program. 294 When combined with reduced generation, either at the affected EGU or elsewhere in the interconnected system, these types of actions would be fully equivalent to proposed building block 4 when viewed from a source-category perspective. As noted elsewhere, the EPA has determined not to include proposed building block 4 in the BSER in this final rule. However, the measures in building block 4 would still be available for compliance purposes to the extent permitted under state plans, and the list of actions above indicates the range of ways through which affected EGUs could access this resource. The EPA anticipates that in instances where section 111(d) plans provide for the use of instruments such as emission rate credits 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 emission rate credits will be able to sell those credits and other affected EGUs will be able to purchase them.

294 For affected EGUs subject to a rate-based form of CO2 performance standard, the section 111(d) plan would need to provide a mechanism by which the affected unit could account for the emissions-reducing benefit of the investment when computing its emission rate for purposes of determining compliance with the performance standard. This mechanism could be similar to the mechanism required with respect to investments in building blocks 2 and 3, although use of demand-side energy efficiency measures involves some additional considerations as well. Further discussion can be found in section VIII below and in the Rate-based Program Accounting TSD for the CPP Final Rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 312 of 1275 Such markets have developed for other instruments used for emissions trading purposes. If states choose to allow through section 111(d) plans a mechanism involving instruments such as emission rate credits –- and, as indicated above, the record strongly indicates that they can be expected to -- there is no reason to expect a shortage of supply of such credits. 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 2 emission performance rates reflecting application of the BSER. In addition, if emission limits are set

at the CO 2 emission performance rates, affected sources in the Western and Texas Interconnections on average do not need to implement the building blocks to their full extent in order to achieve their emission limits because the performance rates for sources in these regions are set at the less stringent rates determined to be reasonable for application of the BSER to sources in the Eastern Interconnection. Further, to the extent that section 111(d) plans take advantage of the final rule’s flexibility to allow the use of multi-state emissions trading or other multi-unit compliance approaches among sources in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 313 of 1275 different Interconnections, all sources can take advantage of the headroom available in other Interconnections. As a result, significant amounts of existing NGCC capacity and potential for renewable energy remain available to serve as the basis for

issuance of credits for all affected EGUs in both source subcategories to rely on to achieve their emission limits. Because this rule includes by express design a variety of options that states and utilities can select to pursue interstate compliance regimes that mirror the interconnected operation of the electricity system, the EPA believes that it is reasonable to anticipate as highly likely that a virtually nationwide emission trading market for compliance will emerge, and that these credits will be available to any source wherever located, as long as its state plan authorizes their purchase and use in meeting the standard of performance the state

establishes. It should also be noted that although 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 an emissions limit set in an emission rate-based form if, as expected, the state chooses to authorize a mechanism for doing so, they are not taken into account directly in computations to determine whether an individual affected EGU has*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 314 of 1275 achieved an emissions limit set in a mass-based form. However, by reducing generation and therefore CO 2 emissions from the group of affected EGUs within a region, these measures facilitate the ability of the individual EGUs within the region to achieve mass-based limits by choosing to reduce their own generation and

emissions. (b) Reduced generation. 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 2 emissions, then, if the affected EGU is subject to an emission rate limit, the owner/operator will need to implement fewer of the building block measures, e.g., buy fewer emission rate credits, to achieve its emission rate; and if the affected EGU is subject to a mass emissions limit, the owner/operator will need fewer mass

allowances. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 315 of 1275 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 steam EGUs, reducing their generation in the amounts of building blocks 2 and 3, and individual affected NGCC units, reducing their generation in the amounts of building block 3, can in aggregate achieve the requisite level of reductions in generation adequate to achieve emission limits reflecting the BSER. 295 With emission limits for the source category as a whole in place, the resulting reduction in supply of higher-emitting generation will incentivize additional utilization of existing NGCC capacity, and the resulting reduction in overall fossil fuel-fired generation will incentivize investment in additional renewable energy generating capacity, and the integrated system’s response to these incentives will ensure that the demand for electricity services

will continue to be met.

295 For purposes of this discussion, we assume that coal-fired steam generators also implement building block 1 measures so that they will implement the full set of measures needed to achieve their emission limit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 316 of 1275 (c) Emissions trading. As described above, viewed from the source-category perspective, the BSER implicitly includes an element of source-category-wide multi-unit compliance, which at the level of implementation could be realized through trading of

rate-based emission credits or mass-based emission allowances. Indeed, as we have already observed, the comment record provides ample evidence that states themselves anticipate establishing standards of performance that allow the use of emissions trading or other multi-unit compliance approaches, and the guidelines’ reliance on state level goals as the basis on which states must demonstrate compliance can be expected to be the cornerstone on which states construct plans that rely, at least implicitly, on multi-unit compliance. The inclusion in the guidelines –- at the request of states and utilities –- of provisions that allow states to create “trading ready” plans for the purpose of facilitating interstate emissions trading or other multi-unit compliance approaches, as discussed in section VIII, is further evidence that utilities as well as states anticipate standardsof performance that rely on emissions trading or other multiunit compliance approaches. Emissions trading, whether implemented through rate-based or mass-based standards of performance, enables the building blocks to be implemented by the EGUs with the lowest costs, and the overall costs to be*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 317 of 1275 distributed throughout the existing source universe, such that costs can be reduced for the source category and for many individual affected EGUs. By the same token, viewed from the individual-source perspective, 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 sources’ section 111(d) plans and would have to meet conditions set out for such approaches in section VIII below, but the record provides ample evidence that such authorization can be expected and section VIII addresses the necessary conditions extensively. It has been recognized for decades, starting with the Acid

Rain SO 2 trading program under Title IV of the CAA, that the availability of emissions trading facilitates the implementation of control measures and reduces their cost. For example, in this rule, while each affected EGU could, in theory, implement each of the building blocks, some affected EGUs would face lower costs in doing so than others, at least for individual building blocks and likely for the combination of all three building blocks as well. Thus, the EPA expects that affected EGUs for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 318 of 1275 whom application of one or more building blocks is relatively less expensive may overcomply. As a result, to the extent that the applicable section 111(d) plans permit emissions trading, the EGUs that overcomply would have rate-based emission credits or mass-based emission allowances to sell, which would enable affected EGUs for whom compliance is relatively more expensive to achieve their emission limits by purchasing those credits or allowances. Any of the building blocks could be the basis for overcompliance and consequent creation of a surplus of credits

or allowances. When an EGU obtains an emission rate-based credit or mass-based allowance from another EGU, that is effectively the same as investing directly in the control measures that created the surplus, such that when emissions trading is permitted, all of the building blocks are effectively available to all affected EGUs through “cross investment” using emission credits or allowances. EGUs currently operating under a variety of pollution control programs incorporating emissions trading have effectuated such investments and actions through the purchase of surplus emissions reductions, in that the purchase price represents investment in other EGUs’ pollution reduction actions that encompass a range of activity, including the use of cleaner generation.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 319 of 1275 (d) Other multi-unit compliance approaches. The set of multi-unit compliance approaches inherent in the BSER because of the global nature of the CO 2 pollutant and the interconnected nature of the electricity system is broader than just the emissions trading approaches described above. In addition to emissions trading approaches -– in essence, multi-unit compliance approaches that use tradable emission credits or

allowances as marketable instruments to facilitate coordination among the sets of participating units -– it is possible for section 111(d) plans to provide for the use of multi-unit approaches that do not involve tradable instruments. Although potentially somewhat less flexible than emissions trading approaches, other types of multi-unit compliance approaches generally offer the same ability for affected sources with lower-cost emission-reduction opportunities to overcomply and to make surplus emission reductions available for use by affected sources with higher-cost emission-reduction opportunities. Thus, like emissions trading, these approaches effectively make it possible for affected EGUs to invest in emission reduction measures that are physically implemented at other locations, consistent with longstanding practice in the interconnected electricity system.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 320 of 1275 For units subject to rate-based performance standards, multi-unit compliance approaches other than emissions trading approaches would generally be “averaging” approaches where multiple units would combine their monitored emissions and generation (as well as any authorized emission rate credits representing the emissions-reducing benefits of investments in specific emissions-reducing activities) in order to compute a combined emission rate that would, in turn, be compared to a combined rate-based performance standard. For units subject to mass-based performance standards, such approaches would generally be “aggregation” approaches where multiple units would combine their monitored emissions in order to compute a combined total mass of emissions that would, in turn, be compared to a combined mass-based performance standard. 296 The use of averaging or aggregation approaches would have to be authorized in the 111(d) plans covering all the participating affected sources and would have to meet conditions set out for such approaches in

section VIII below.

f. Measures that reduce CO 2 emissions or CO 2 emission rates but

are not included in the BSER. There are numerous other measures that are available to at least some affected EGUs to help assure

296 Approaches that aggregate emissions of multiple units at a single facility are commonly known as “bubbling” approaches.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 321 of 1275 that they can achieve their emission limits, even though the EPA is not identifying these measures as part of the BSER. These measures include demand-side energy efficiency implementable by affected EGUs; new or up-rated nuclear generation; renewable measures other than those that are part of building block 3, including distributed generation solar power and off-shore wind; combined heat and power and waste heat power; and transmission and distribution improvements. In addition, a state may implement measures that yield emission reductions for use in reducing the obligations on affected EGUs, such as demand-side energy efficiency measures not implementable by affected EGUs, including appliance standards, building codes, and drinking water or wastewater system efficiency measures. The availability of these measures further assures that the appropriate level of

emission reductions can be achieved and that affected EGUs will

be able to achieve their emission limits. g. Ability of EGUs to implement the BSER. The EPA’s analysis, based in part on observed decades-long behavior of EGUs, shows that all types and sizes of affected EGUs in all locations are able to undertake the actions described as the BSER, including investor-owned utilities, merchant generators, rural cooperatives, municipally-owned utilities, and federal utilities. Some may need to focus more on certain measures; for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 322 of 1275 example, an owner of a small generation portfolio consisting of a single coal-fired steam EGU may need to rely more multi-unit compliance approaches, possibly including the purchase of emission credits or allowances, because of a lack of sufficient scale to diversify its own portfolio to include NGCC capacity and renewable capacity in addition to coal-fired capacity. As noted elsewhere, as a legal matter, it is not necessary that each affected source be able to implement the BSER, but in any event, in this rule, all affected EGUs can do so. Affected EGUs may rely on emissions trading or other multi-unit compliance approaches authorized under their states’ section 111(d) plans to, in effect, invest in building block measures that are physically implemented at other locations. As discussed above, the EPA’s quantification of the CO 2 emission performance rates in a manner that provides headroom within the BSER also contributes to the ability of all affected EGUs to implement the BSER and achieve emissions limitations consistent with those performance

rates. h. Subcategorization. As noted above, in this rule, we are treating all fossil fuel-fired EGUs as a single category, and, in the emission guidelines that we are promulgating with this rule, we are treating steam EGUs and combustion turbines as separate subcategories. We are determining the BSER for steam*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 323 of 1275 EGUs and the BSER for combustion turbines, and applying the BSER to each subcategory to determine a performance rate for that subcategory. We are not further subcategorizing among different types of steam EGUs or combustion turbines. As we discuss below, 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 section 111, which require the EPA first to list source categories that may reasonably be expected to endanger public health or welfare and then to regulate new sources within each such source category, and which grant the EPA discretion whether to subcategorize the sources for purposes of determining the BSER. 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 what multi-unit compliance approaches to permit, possibly including emissions trading approaches -- including investment in the building blocks, replaced or reduced generation, and emissions trading or other multi-unit compliance*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 324 of 1275 approaches. 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 energy efficiency measures. Such compliance options may also indirectly help affected sources 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.

3. Changes from proposal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 325 of 1275 For the BSER determined in this final rule, based on consideration of comments, the EPA has adopted certain refinements to the proposed BSER. In this subsection we describe the most significant refinements, including some that relate to individual building blocks and some that are more general. Additional refinements 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 refinements yield emission reductions requirements that commence more gradually than the proposed goals but are projected to produce slightly greater emission reductions overall by 2030. We also note that the refinements lead to requirements that are more uniform across states than was the case in the proposal.

a. Interpretations of CAA section 111. In the June 2014 proposal, the EPA proposed interpretations of section 111(a)(1) and (d), and applied these interpretations to existing fossil fuel-fired

EGUs. 297 Informed by comments, the EPA has clarified some of these interpretations, and has developed a more refined understanding of how some of these interpretations should be

297 The June 2014 proposal in part referenced proposed interpretations of section 111(a)(1) that the EPA explained in the January 2014 proposal to address CO 2 emissions from new fossil fuel-fired EGUs under section 111(b).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 326 of 1275 applied. The clarified and more refined interpretations replace the proposed interpretations, as indicated in section V.A.1. and the Legal Memorandum for the CPP Final Rule available in the docket, as well as in the final rule for new sources promulgated concurrently with this final rule for existing sources. 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 sources being able to implement the measures themselves (e.g., appliance standards or building codes). In the final rule, we have clarified that the components of the BSER must be implementable by the affected sources, not by the states, and we show that all the components of the BSER have been demonstrated

to be achievable on that basis without reliance on actions that can only be accomplished through state mandates. Further discussion of these points can be found throughout this section on the BSER and the following sections on the individual building blocks. Second, the EPA has adopted a combined interpretation of sections 111(a)(1) and 111(d) that, compared to the proposal, places more weight on the historical interpretations of section 111(a)(1), which have generally supported emissions standards*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 327 of 1275 that are nationally uniform for sources incorporating a given technology, and less weight on 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 sources in each individual state, and because the relative magnitudes of these opportunities varied by state, sources incorporating the same technology could have faced disparate standards of performance (depending to some extent on how the states chose to distribute the emission reduction requirements among their individual sources). Some commenters viewed this potential result as inconsistent with section 111(a)(1), inequitable, or both. While we continue to believe that, for the purposes of this rule, the focus of section 111(d) on individual state plans could justify an interpretation of section 111(a)(1) that emphasizes maximization of state-by-state emission reduction opportunities, we have determined that by assessing the emission reduction opportunities at an appropriate regional scale, it is possible to reconcile the use of uniform emissions standards by technology with the state-focused 111(d) scheme. The methodological refinements related to regional assessment of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 328 of 1275 emission reduction opportunities and the use of uniform emissions standards by technology are further discussed below.

b . Approach to quantification of emission reductions from increased RE generation. In the June 2014 proposal, the EPA described two possible approaches for quantifying the amount of emission reductions achievable from affected EGUs through the use of renewable energy generation. The proposed approach used information on state RPS aggregated at a regional level to project the amount of RE generation used in quantifying the emission reductions achievable through the BSER. The alternative approach used information on the technical and market potential for development of renewable resources in each state to project the RE-related emission reductions. In the October 30, 2014 Notice of Data Availability, we provided notice that some commenters had suggested modifying the alternative approach to aggregate the state-level information to a regional level. In this final rule we are adopting the alternative approach from the proposal, modified as described in the NODA. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 329 of 1275 terms of total rather than incremental generation. Commenters observed that this quantification 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 affectedEGUs from 2012 levels. As just noted, we are not using the RPSbased 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. 298 Further details regarding the final rule’s quantification of RE generation are provided in section V.E. below.

c

298 Generation from existing RE capacity will continue to make compliance with mass-based standards easier to achieve by making the overall amount of fossil fuel-fired generation that is required to meet the demand for energy services lower than it would otherwise be, thereby keeping CO 2 emissions lower than they would otherwise be.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 330 of 1275

. Exclusion from the BSER of emission reductions from use of new or preserved nuclear capacity. In the June 2014 proposal, the EPA included in building block 3 provisions reflecting the ability for nuclear generation to replace fossil generation and thereby reduce CO 2 emissions at affected sources. We proposed to include in building block 3 the potential generation from five under-construction nuclear generating units whose construction had commenced prior to the issuance of the proposal. In addition, to address the potential that some currently operating nuclear facilities may shut down prior to 2030, the proposal incorporated into the BSER for each state with nuclear capacity a projected 5.8 percent reduction in nuclear generation, based on an estimate of potential nationwide loss of nuclear generation from existing units. We sought comment on all aspects of these proposed approaches. For this final rule, the BSER does not include either of the components related to nuclear generation. The EPA received numerous comments on the proposed BSER components related to nuclear power. With respect to generation from new 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 new units*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 331 of 1275 are being built and that the inclusion of the generation in the goals is premature because the units’ actual completion dates are uncertain. Some commenters expressed concern regarding the lack of flexibility to find alternative emission reduction measures comparable in magnitude to the assumed emission reductions from the new nuclear generation in the event that construction was not completed, potentially hampering the ability to achieve the state goals. Commenters also stated that inclusion of the new nuclear generation in the BSER would be inequitable because states where the same heavy investment in

zero-CO 2 generation was not being made would have relatively less stringent goals. 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 is 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,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 332 of 1275 although we believe that other refinements to this final rule

would address commenters’ concerns that host states would be at risk of being unable to achieve their goals if the units were not completed, we also acknowledge that including generation from the units in the BSER would fail to recognize the significant ongoing commitment required to complete these major investments by instead treating them as though there were no chance they would not be completed. 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 retirement. Further, based in part on comments received on another aspect of the proposal –- specifically, the proposed inclusion of existing RE generation in the goal-setting computations –- we believe that it is inappropriate to base the BSER in part on the premise that the preservation of existing low- or zero-carbon generation, as opposed to the production of incremental, low- or zero-carbon generation, could reduce CO 2 emissions from current levels. Accordingly, we have determined

not to reflect either of the nuclear elements in the final BSER.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 333 of 1275 Generation from 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 of credits, as discussed in section V.A.6.b., and would help sources meet mass-based standards of performance through reduced utilization of fossil generating capacity leading to

reduced CO 2 emissions at affected EGUs. However, consistent with the reasons just discussed for not reflecting preservation of existing nuclear capacity in the BSER –- namely, that such preservation does not actually reduce existing levels of

emissions from affected EGUs –- the rule does not allow preservation of generation from existing nuclear capacity to

serve as the basis for creation of credits that individual affected EGUs could use for compliance. 299

d. Exclusion from the BSER of emission reductions from demandside energy efficiency. The June 2014 proposal included demandside energy efficiency measures in building block 4 as part of the BSER, but the EPA is not finalizing that part of the proposal, for the following reasons.

299 As with generation from existing RE capacity, generation from existing nuclear capacity will continue to make compliance with mass-based standards easier to achieve by making the overall amount of fossil fuel-fired generation that is required to meet the demand for energy services lower than it would otherwise be, thereby keeping CO 2 emissions lower than they would otherwise be.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 334 of 1275 Building block 4 caused more controversy among commenters than any other aspect of the June 2014 proposal. While many commenters emphasized the cost-effectiveness of demand-side energy efficiency measures, others expressed significant

concerns. As a legal matter, commenters emphasized that demand-side energy efficiency measures reduce emissions from the generation of electricity by reducing overall demand for electricity and that this is different from generation shifts and renewable energy. Commenters also asserted that those differences arelegally significant for purposes of determining whether demandside energy efficiency measures may qualify as part of the BSER. Commenters viewed demand-side energy efficiency as a restriction on the amount of electricity that the affected industry could generate, and they viewed that type of restriction as beyond the scope of the EPA’s authority under CAA section 111. The demand-side energy efficiency measures in building block 4 are different in certain respects from the generation shifts and renewable energy measures in building blocks 2 and 3. As noted, the generation shifts and renewable energy measures are mechanisms through which affected EGUs may generate the same electricity (which is a fungible product) with fewer CO 2 emissions whereas the demand-side energy efficiency measures in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 335 of 1275 building block 4 do not provide the same amount of generation but through cleaner processes, and instead bring about reductions in demand for electricity, which avoids the need for variable generation, which tends to be higher-emitting. Commenters also assert that inclusion of building block 4 would amount to an attempt to extend EPA regulation beyond emitting sources to electricity end-users, and they observe that such an extension would exceed the EPA’s authority. While we do not agree that inclusion of building block 4 in the BSER would be equivalent to regulation of electricity end-users, the legal uncertainty associated with this claim would increase the uncertainty for states during a window of time when significant progress must be made on their section 111(d) plans, potentially hindering those planning efforts. In addition, commenters noted that as a practical matter, demand-side energy efficiency programs involve the participation of more entities, including end-users, which creates levels of complexity in implementation not found with the other building

blocks. Commenters also asserted that the record for the proposal lacked information demonstrating that a number of states could implement demand-side energy efficiency programs in the amounts and on the time-table that the proposal called for, or that certain segments of the industry –- independent power*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 336 of 1275 producers, who comprise some 35-40 percent of the industry, but do not have a direct business relationship with end-users –-

could do so. Upon consideration of the variety of points raised above, without necessarily agreeing with those points, the EPA has determined not to include demand-side energy efficiency in the

BSER in this final rule. It should be noted that commenters also took the position that the EPA should allow demand-side energy efficiency as a means of compliance with the requirements of this rule, and, as discussed below, we agree.

e . Consistent regionalized approach to quantification of emission reductions from all building blocks. In the June 2014 proposal, the EPA treated each of the building blocks differently with respect to the regional scale on which the building block was applied for purposes of assessing the emission reductions achievable through use of that building block. Building block 1 was quantified at a national scale, identifying a single heatrate improvement opportunity applicable on average to all coalfired steam EGUs. Building block 2 was quantified at the scale of each individual state, considering the amount of generation

that could be shifted from steam EGUs to NGCC units within the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 337 of 1275 state, although we solicited comment on considering generation shifts at a broader regional scale. The RE component of building block 3 was quantified at a regional scale using RPS information as a proxy for RE development potential, and the regional results were then applied to each state in the region using the state’s baseline data; an alternative methodology on which werequested comment quantified the RE component using a technoeconomic approach on a state-specific basis. 300 For the final rule, with the benefit of comments received, we have adopted a consistent regionalized approach to quantification of emission reductions achievable through all the building blocks. The regions we have determined to be appropriate for this purpose are the Eastern, Western, and Texas Interconnections, as we explain in more detail below. 301 Each of the building blocks is quantified and applied at the regional level, resulting in the computation for each region of a

300 For building block 4, potential demand-side EE was first quantified on a state-specific basis but the emission reduction consequences for electricity-importing states were then adjusted downward in the goal setting process in order to account for regional effects; we solicited comment on making parallel upward adjustments to the goals for net electricity-exporting states to account for the regional effects more completely. 301 The Texas Interconnection encompasses the portion of the Texas electricity system commonly known as ERCOT (for the Electric Reliability Council of Texas). The state of Texas has areas within the Eastern and Western Interconnections as well as the Texas Interconnection.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 338 of 1275 performance rate for steam EGUs and a performance rate for NGCC units. We then apply these performance rates to the baseline data for each state in a region to establish state goals of consistent stringency across the states (although the actual state goals vary among states to reflect the differences in generation mix among states). 302 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.) and CO 2 emission performance rate and state goal computation (sections VI and VII), as well as the GHG Mitigation

Measures TSD for the CPP Final Rule and the CO 2 Emission Performance Rate and Goal Computation TSD for the CPP Final Rule

available in the docket.

In determining that the appropriate regional level for quantification of the BSER was the level of the interconnection, the EPA considered several factors. First, we considered the regional scale on which electricity is actually produced, coordinated, and consumed in real time, and concluded that the

302 As discussed below, we have determined that it is appropriate to go further and to use the single most conservative – that is, the least stringent – set of the three regionally developed uniform emissions standards to establish state goals for the states, in all three regions, thereby ensuring a consistent stringency of goals for all states.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 339 of 1275 three large interconnections –- Eastern, Western and Texas –- were more appropriate than subregions within these interconnections. The Bulk Power System (BPS) in the contiguous United States (including adjacent portions of Canada) consists of three interconnections, which are alternating current (AC) power grids where power flows freely from generating sources to consuming loads. These interconnections are separately plannedand operated; they are connected to each other only through lowcapacity direct current (DC) tie lines. Each interconnection is managed to maintain a single frequency and to maintain stable voltage levels throughout the interconnection. 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 –- with the borders of the subregions occasionally changing as planning and management functions evolve or as owners of various portions of the grid change affiliations –- those activities always occur in the context of the interconnections, whose boundaries change much less often. The need to maintain common frequency and stable voltage levels throughout the interconnections requires constantly changing flows of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 340 of 1275 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 regions 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 341 of 1275 interconnections as the ultimate regions within which electricity supply and demand must balance. Second, 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 renewable energy throughout each interconnection -- as well as the management of the interconnected grid as loads are reduced through energy efficiency, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 342 of 1275 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 transmissionconstraint requires that for reliability reasons a higheremitting 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 343 of 1275 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 sources 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 344 of 1275 activities, such as renewable energy certificates, 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

source should also limit the source’s transactions for emission rate credits or 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 2 pollution do not necessitate geographic constraints, and in the absence of a policy reason to constrain the geographic scope of trading, the largest possible scope is the most efficient scope.

f

. Uniform CO 2 emission performance rates by technology type. In conjunction with the refinements to the interpretations of section 111 reflected in the final rule, the EPA has refined the methodology for applying the BSER to the affected sources so as to incorporate performance rates that are uniform across technology types.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 345 of 1275 Specifically, the final rule reflects a performance rate of 1290 lbs. per net MWh for all affected steam EGUs nationwide and a performance rate of 780 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. This refinement is consistent with a number of comments we received on the proposal and is a logical outgrowth of the proposal informed by the comments. 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. In section VI, below, we describe how we use data assembled for the building blocks through the consistent regional approach described above to determine for each region a set of uniform performance rates representing emission limits achievable through the application of the BSER to the subcategory of steam EGUs and the subcategory of NGCC units. Recognizing the comments favoring the use of nationally uniform performance rates by technology, the EPA considered whether any of the regional*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 346 of 1275 performance rates could represent the emission limitation achievable through application of the BSER for its respective source subcategory nationwide. Except for Alaska, Hawaii, Puerto Rico, and Guam, which are geographically isolated from the three major interconnections as well as from one another, the standards developed using data for the Eastern, Western and ERCOT Interconnections represented sufficiently broad

combinations of affected sources and emission reduction opportunities to apply nationally. We also determined that it would be more appropriate to use the least stringent of the regional performance rates for the three interconnections for each technology type as the basis for nationally uniform performance rates for that technology type than to use the most stringent or the region-specific performance rates. This is generally consistent with the approach taken in other NSPS rulemakings, where once the appropriate technology has been identified, stringencies are generally set based on the least stringent level reasonably achieved using that technology. Using the least stringent rate would provide greater “headroom” –- that is, emission reduction opportunities beyond those reflected in the performance rates –- to affected sources in regions not setting the national level, and therefore greater compliance flexibility and assurance that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 347 of 1275 the standards would be achievable at reasonable cost, while still representing an appropriately large set of emission reduction opportunities to reasonably be considered the “best” system of emission reduction for each technology type. We have determined that the nationwide performance rates should not necessarily apply to states and territories that are isolated from the three major interconnections –- that is, Alaska, Hawaii, Puerto Rico, and Guam 303 –- because affected EGUs in those areas lack the same opportunities to access the building blocks across wide regions that affected EGUs in the contiguous states enjoy. Instead, if the performance rates computed using data specific to one of these isolated states or territories is less stringent than the nationwide performance rates, we have determined that the less stringent state- or territory-specific rates should apply. The computations of the regionally uniform performance rates for each of the three major interconnections as well as Alaska, Hawaii, Guam, and Puerto Rico are shown in the Final Rule Goal Computations TSD.

303 The section 111(d) requirements do not currently apply to the other isolated U.S. territories –- the U.S. Virgin Islands, American Samoa, and the Northern Mariana Islands –- because no affected EGUs currently operate in these territories.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 348 of 1275 g. Establishment of a 2022-2029 interim compliance period. The June 2014 proposal separately quantified emission limitations applicable to an interim 2020-29 period and to the period beginning in 2030. Although the proposal provided flexibility in the timing with which emission reductions could be made over the course of the 2020-2029 period in order to achieve compliance with the emission limitations applicable to that interim period, many commenters perceived the start of the period as too soon and stated that it provided insufficient time for planning and investments necessary for sources to begin complying while maintaining reliable electricity supplies.

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 given the nature and magnitude of planning and investment activities that will be necessary to begin compliance with the final rule’s requirements in an orderly manner while maintaining reliability of electricity supplies. Further discussion is provided in the sections of the preamble addressing the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 349 of 1275 individual building blocks and on electricity system reliability.

h. Refinements to stringency for individual building blocks. For each individual building block, the EPA has reexamined the data and assumptions used at proposal in light of comments received, and has made a number of refinements in the final rule in light

of that information. The refinements are discussed in the preamble sections for each building block (sections V.C., V.D., and V.E.) and goal computation (section VI) and in the GHG Mitigation Measures TSD for the CPP Final Rule and the CO 2 Emission Performance Rate and Goal Computation TSD for the CPP Final Rule. In general, viewed in terms of projected nationwide emission reductions, these refinements tend to make the interim goals somewhat less stringent than at proposal with the 2030 goals being either at the same level of stringency as that of the proposal or at a somewhat more stringent level. In addition to the changes described above, the refinements include the following:

 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 350 of 1275

 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 renewable energy costs and potential, and revision of the list of quantified RE technologies to exclude landfill gas under building block 3.

4. Determination of the BSER 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 source-category perspective. Each building block includes a set of actions and facilitating mechanisms that individual sources can use to achieve the emission limitations reflecting the BSER. These actions and mechanisms, which include reduced generation and emissions trading or other multi-unit compliance approaches, represent the BSER from the individual-source perspective and will be discussed below in section V.A.5. As discussed above, one of the refinements being made in this rule is the establishment of uniform performance rates by technology type. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 351 of 1275 electricity system and the region-wide scope of opportunities available for affected sources in each region to access emission reduction measures. However, 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. In order to achieve uniform performance rates by technology type, and to do so in a way that respects 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 type, the BSER is the combination of the elements described above at the combined stringency that is reasonably achievable in the Eastern Interconnection, which is the region

where the CO 2 emission performance rates determined to be

achievable at reasonable cost for both steam EGUs and combustion turbines were least stringent. (For the isolated states and territories of Alaska, Hawaii, Puerto Rico, and Guam, if the performance rates determined to be achievable at reasonable*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 352 of 1275 costs based on the application of the BSER to that state or territory are less stringent than the nationwide rates, the state- or territory-specific performance rates are used instead.) This approach is consistent with the approach we have taken in other NSPS rulemakings, where the BSER for each subcategory of affected sources generally has been determined not on the basis of what is achievable by the sources that can reduce emissions most easily, but instead on the basis of the least stringent rate that is reasonably achievable. This approach also provides compliance headroom –- in addition to the headroom provided by our approach to setting the stringency for each individual building block -- for affected EGUs in regions

where the emission reductions that could be achieved at

reasonable cost exceed the reductions that are achievable at reasonable cost in the limiting region, thereby promoting compliance flexibility. Further, because we are not geographically restricting the opportunity of affected EGUs to engage in emissions trading or other multi-unit compliance approaches to the extent allowed under the relevant section 111(d) plans, the availability of additional, lower-cost emission reduction opportunities in other regions will also promote compliance flexibility and reduces compliance costs. Briefly, the elements of the BSER are:*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 353 of 1275 Building block 1 : Reducing the carbon intensity of generation at individual affected coal-fired steam EGUs through heat rate improvements in specified percentages. Building block 2 : Substituting increased generation from existing affected NGCC units for reduced generation from affected steam EGUs in specified quantities. Building block 3 : Substituting generation from new low- or zero-carbon generating capacity for reduced generation from affected EGUs in specified quantities.

a. Building block 1. Building block 1 -- reducing the carbon intensity of generation at individual affected coal-fired steam EGUs through heat rate improvements -- is a component of the BSER with respect to coal-fired steam EGUs 304 because the measures the affected sources may undertake to achieve heat rate improvements are technically feasible and of reasonable cost, and perform well with respect to other factors relevant to a determination of the “best system of emission reduction ... adequately demonstrated.” Building block 1 is a “system of

304 For the reasons discussed in the proposal, the EPA is not determining that heat rate improvements at other types ofaffected EGUs, such as NGCC units and oil-fired and natural gasfired steam EGUs, are components of the BSER. However, all types of affected EGUs would be able to employ heat rate improvements as measures to help achieve compliance with their assigned standards of performance.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 354 of 1275

emission reduction” for steam EGUs because owners of these EGUs can take actions that will improve their heat rates and thereby

reduce their rates of CO 2 emissions with respect to generation. The EPA has analyzed the technical feasibility, costs, and magnitude of CO 2 emission reductions achievable through heat rate improvements at coal-fired steam EGUs based on engineering studies and on these EGUs’ reported operating and emissions data. We conclude that taking action to improve heat rates is a common and well-established practice within the industry that is capable of achieving meaningful reductions in CO 2 emissions at reasonable cost. Specifically, we have determined that an average heat rate improvement ranging from 2.1 to 4.3 percent by all affected coal-fired EGUs, depending on the region, is an element of the BSER, based on the inclusion of those amounts of improvement in the three regions, determined through our regional analysis. Our analysis and conclusions are discussed in Section V.C. below and in the GHG Mitigation Measures TSD for

the CPP Final Rule.

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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 355 of 1275 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 BSER without reference to technological innovation, we will 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 2 emissions from coal-fired EGUs, heat rate improvements and consequent variable

cost reductions at those EGUs would cause them to become more competitive compared to other EGUs and increase their generation, leading to smaller overall reductions in CO 2 emissions (depending on the CO 2 emission rates of the displaced generating capacity). However, we believe that this concern can be readily addressed by ensuring that the BSER also reflects

other CO 2 reduction strategies that encourage increases in generation from lower- or zero-carbon EGUs or in demand-side energy efficiency, thereby allowing building block 1 to be*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 356 of 1275 considered an appropriate part of the BSER for CO 2 emissions at affected EGUs as long as the building block is applied in combination with other building blocks. 305

b. Building block 2. Building block 2 –- reducing CO 2 emissionsat, and substituting for generation from, the most carbonintensive affected EGUs with generation from less carbonintensive affected EGUs (specifically NGCC units that are currently operating or under construction) –- is a component of the BSER for steam EGUs because generation shifts that will

reduce the amount of CO 2 emissions at higher-emitting EGUs and from the source category as a whole are technically feasible, are of reasonable cost, and perform well with respect to other factors relevant to a determination of the “best system of emission reduction ... adequately demonstrated.” Building block 2 is a “system of emission reduction” for steam EGUs because incremental generation from existing NGCC units will result in reduced generation and emissions from steam EGUs, and owners of steam EGUs can, and many do, invest in incremental generation

305 Concern about a rebound effect could also be addressed by requiring that standards of performance for affected EGUs be set in the form of mass-based caps, but the EPA has determined that it is appropriate to allow states the flexibility to establish either emission rate-based or mass-based standards of performance for their affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 357 of 1275 from NGCC units through a variety of possible mechanisms. A steam EGU investing in incremental generation from NGCC units may choose to reduce its own generation or may maintain its generation level and choose to allow the reduction in generation to occur at other steam EGUs through the coordinated planning and operation of the interconnected electricity system. An affected EGU may also invest in emission reductions from building block 2 through the mechanism of engaging in emissions trading. The EPA’s analysis and conclusions regarding the technical feasibility, costs, and magnitude of CO 2 emission reductions achievable at high-emitting EGUs through generation shifts to lower-emitting affected EGUs are discussed in Section V.D. below. We consider generation shifts among the large number of diverse EGUs that are linked to one another and to customers byextensive regional transmission grids to be a routine and wellestablished operating practice within the industry that is used to facilitate the achievement of a wide variety of objectives, including environmental objectives, while meeting the demand for electricity services. In the interconnected and integrated electricity industry, fossil fuel-fired steam EGUs are able to reduce their generation and NGCC units are able to increase their generation in a coordinated manner through mechanisms –-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 358 of 1275 in some cases centralized and in others not -- that regularly deal with such changes on both a short-term and a longer-term basis. Our analysis demonstrates that the emission reductions that can be achieved or supported by such generation shifts are substantial and of reasonable cost. Further, both the achievability of this building block and the reasonableness ofits costs are supported by the fact that there has been a longterm trend in the industry away from coal-fired generation and toward NGCC generation for a variety of reasons. Building block 2 is adequately demonstrated as a “system of

emission reduction” for affected steam EGUs. As discussed in section V.B., Congress has long recognized that generation shifts among EGUs are one means of reducing emissions from the utility power sector and multiple provisions of the CAA reflect that recognition, and generation shifts similarly have been recognized as 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 ofemission allowances as a variable cost when making securityconstrained, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 359 of 1275 V.D. Thus, legislative history, regulatory precedent, and industry practice support interpreting the broad term “system of emission reduction” as including 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 operating an NGCC unit it already owns more or by purchasing an existing NGCC unit and operating that unit more. Increases in generation by NGCC units over baseline levels can also serve as

the basis for creation of CO 2 emission rate credits (ERCs) –- that is, instruments representing the ability of incremental electricity generated by NGCC units to cause emission reductions at affected steam EGUs, as distinct from the incremental electricity itself. Again, it is important to note that the acquisition of such ERCs, represents an investment in the actions of the facility or facilities whose alteration of utilization levels generated the emissions rate improvement or reduction. In the context of the BSER, purchase of instruments representing the emissions-reducing benefit of an action is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 360 of 1275 simply a medium of investment in the underlying emissions

reduction action. These mechanisms are discussed further in section V.A.5. In this rule, the EPA is establishing minimum criteria for the creation of valid emission rate credits by NGCC units and for the use of such credits by affected steam EGUs for demonstrating compliance with emission rate-based standards of performance established under state plans. The existence of minimum criteria will ensure that crediting mechanisms are feasible and will facilitate the development of organized markets to simplify the process of buying and selling credits.

The minimum criteria are discussed in section VIII of this preamble. We note that an affected source 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 requirements that will be imposed on

affected sources 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 requirements, the decrease in generation resulting from that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 361 of 1275 coordinated operation is most likely to be generation from an affected steam EGU. Measures taken by affected sources that

result in emission reductions from other sources in the source category may appropriately be deemed components of a “system of

emission reduction.” 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. 306 With respect to energy impacts, building block 2 represents replacement of electrical energy from one generator with electrical energy from another generator

306 For example, according to a DOE/NETL study, the relative amount of water consumption for a new pulverized coal plant is 2.5 times the consumption for a new NGCC unit of similar size. “Cost and Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous Coal and Natural Gas to Electricity,” Rev 2a, September 2013, National Energy Technology Laboratory Report DOE/NETL-2010/1397. EPA believes the difference would on average be even more pronounced when comparing existing coal and NGCC units.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 362 of 1275 that consumes less fuel, so the overall energy impact should be a reduction in fuel consumption by the overall source category as well as by individual affected coal-fired steam EGUs. Although we consider the incentive for technological advancement only in the alternative, we note that building block 2 does not call for deployment of new technology, but does promote greater use of the NGCC technology installed in the existing fleet of NGCC units, which is newer and more advanced than the technology installed in much of the older existing fleet of steam EGUs. For all these reasons, the measures in building block 2 qualify as a component of the “best system of emission reduction ... adequately demonstrated.” 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. 307 Through application of this building block considered in isolation, some affected sources –- mostly coal-fired steam EGUs -- would reduce their generation

and CO 2 emissions, while other affected sources –- NGCC units –- would increase their generation and CO 2 emissions. However,

307 For purposes of this rulemaking, “existing” EGUs include units under construction as of January 8, 2014, the date of publication in the Federal Register of the Carbon Pollution Standards for new fossil fuel-fired EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 363 of 1275 because for each MWh of generation, NGCC units produce fewer CO 2 emissions than coal-fired steam EGUs, the total quantity of CO 2 emissions from all affected sources in aggregate would decrease. In the context of the integrated electricity system, where the operation of affected EGUs of multiple types is routinely coordinated to provide a fungible service, and in the context of

CO 2 emissions, where location is not a consideration, in contrast with other pollutants, a measure that takes advantage of that integration to reduce CO 2 emissions from the overall set of affected EGUs is readily encompassed within the meaning of a “system of emission reduction” for CO 2 emissions at affected EGUs

even if the measure would increase CO 2 emissions from a subset of those affected EGUs. Indeed, some industry participants are already moving in this direction for this purpose (while other participants are moving in the same direction for other purposes). Emissions trading and other multi-unit compliance approaches can facilitate the implementation of such a “system” and have already been used in the electricity industry to

address CO 2 as well as other pollutants, as discussed above.

c. Building block 3. Building block 3 –- reducing CO 2 emissions at, and substituting for generation from, affected EGUs by using generation from expanded RE generating capacity –- is a component of the BSER because the expansion and use of renewable*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 364 of 1275 generating capacity to reduce emissions from affected sources is technically feasible, will not jeopardize system reliability, is of reasonable cost, and performs well with respect to other factors relevant to a determination of the “best system of emission reduction ... adequately demonstrated.” Building block 3 is a “system of emission reduction” for all affected EGUs because incremental RE generation will result in reduced generation and emissions from affected EGUs, and owners of affected EGUs can invest in incremental RE generation either directly or through the purchase of emission rate credits. An affected EGU investing in incremental RE generation may choose to reduce its own generation by a corresponding amount or may choose to allow the reduction in generation to occur at other affected EGUs through the coordinated planning and operation of the interconnected electricity system. An affected EGU can also invest in RE generation by means of engaging in emissions trading. 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 365 of 1275 pursuing policies that encourage production of greater amounts of renewable energy, such as the establishment of targets for procurement of renewable generating capacity. Moreover, markets are likely to develop for emission rate credits that would facilitate investment in increased RE generation as a means of helping sources comply with their standards of performance; indeed, markets for renewable energy certificates, which similarly facilitate investment in renewable energy 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 sources to reduce their emissions as much as possible, including through substituting for their generation with generation from renewable energy, 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 366 of 1275 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. Operation of new RE generating capacity could also serve as the basis for issuance of an ERC, and the owner of the affected EGU could either operate new RE generating capacity in order to obtain ERCs or 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 2 emission reductions to

occur. These mechanisms are discussed further in section V.A.5. As with building block 2, in this rule the EPA is establishing

minimum criteria for the creation of valid emission rate credits*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 367 of 1275 by new RE generators and for the use of such credits by affected EGUs for demonstrating compliance with emission rate-based standards of performance established under state plans. The existence of minimum criteria will ensure that crediting mechanisms are feasible and will facilitate the development of organized markets to simplify the process of buying and selling

credits. The minimum criteria are discussed in section VIII of the preamble. As with building block 2, an affected source 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 sources in order to meet the emissions standards representing the BSER, an increase in RE generation will be offset elsewhere in the interconnection by a decrease in other generation. Because of the need to meet the collective requirements, the decrease in generation resulting from that coordinated operation is most likely to be generation from an affected EGU. As discussed in section V.B., measures taken by

affected sources that result in emission reductions from other*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 368 of 1275 sources in the source category may appropriately be deemed components of a “system of emission reduction.” 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 intermittent 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 similarly believes that planners and operators will be 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.H.2, will ensure the absence of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 369 of 1275 adverse energy impacts. With respect to technological innovation, an alternative consideration for the BSER, 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. Combination of all three building blocks. The final BSER includes a combination of all three building blocks. For the reasons described below, and similar to each of the building blocks, the combination must be considered a “system of emission reduction.” Moreover, as also discussed below, the combination qualifies as the “best” system that is “adequately demonstrated.” The combination is technically feasible; it is capable of achieving meaningful reductions in CO 2 emissions from affected EGUs at a reasonable cost; it also performs wellagainst the other BSER factors; and its components are wellestablished. The combination of the three building blocks will achieve greater CO 2 emission reductions at reasonable costs than possible combinations with fewer building blocks and will also perform better against other BSER factors. We therefore find the combination of all three building blocks to be the “best system*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 370 of 1275 of emission reduction ... adequately demonstrated” for reducing

CO 2 emissions at affected EGUs. 308 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 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

308 The analysis of the interactions among building blocks provided above for the combination of building blocks 1 and 2, indicating that the addition of building block 2 would mitigate the potential concern about a “rebound effect” if building block 1 were implemented in isolation, applies to the combination of all three building blocks as well; in fact, the addition of building block 3 would further mitigate that concern. The EPA believes that if implemented in combination, each of the three building blocks would achieve substantial reductions in CO 2 emissions from affected EGUs at a reasonable cost.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 371 of 1275 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 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 372 of 1275 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 EGUsconsistent with replacement of generation by lower- or nonemitting EGUs and avoidance of generation through demand-side energy efficiency. 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. In general, building blocks 2 and 3 do not

interact with one another in a manner that would cause the cost of deploying any of these building blocks in combination with the other building blocks to be more than the cost of deploying the respective building block in isolation to the same degree of stringency. The EPA recognizes that as increasing quantities of generation from higher-emitting EGUs are replaced, the avoided*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 373 of 1275cost of the generation that is being replaced by lower- or nonemitting generation decreases, but 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. Moreover, the likely use of emissions trading or other multi-unit compliance approaches, which are inherent in the building blocks as discussed above, will further reduce the overall costs of this rule by facilitating the ability of individual affected EGUs to take advantage of instances where other affected EGUs have opportunities to reduce emissions at

lower cost. 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). 309 However, we

309 If an EGU produces less generation output, then an improvement in that EGU’s heat rate and rate of CO 2 emissions per*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 374 of 1275 believe that the cost of emission reductions achieved through heat rate improvements in the context of a three-building block BSER will remain reasonable for two reasons. First, as discussed in section V.C. below, the cost of CO 2 emission reductions achievable through heat rate improvements is quite low, and that cost will remain reasonable even if it is substantially increased. Second, although under a BSER encompassing all three building blocks the volume of coal-fired generation will decrease, that decrease is unlikely to be spread uniformly among all coal-fired EGUs. It is more likely that some coal-fired EGUs will decrease their generation slightly while others will decrease their generation by larger percentages or cease operations altogether. We would expect EGU owners to take these changes in EGU operating patterns into account when considering where to invest in heat rate improvements, with the result that there will be a tendency for such investments to be concentrated in EGUs whose generation output is expected to decrease the least. This enlightened bias in spending on heat rate improvements –- that is, focusing investments on EGUs where such

unit of generation produces a smaller reduction in CO 2 emissions. If the investment required to achieve the improvement in heat rate and emission rate is the same regardless of the EGU’s generation output, then the cost per unit of CO 2 emission reduction will be higher when the EGU’s generation output is lower.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 375 of 1275 improvements will have the largest impacts and produce the highest returns, given consideration of projected changes in dispatch patterns –- will tend to mitigate any deterioration in

the cost of CO 2 emission reductions achievable through heat rate improvements. For the regulatory impacts analysis accompanying this final rule, the EPA has assessed the costs, benefits, and other impacts of deployment of the final BSER through section 111(d) plans. The analysis reflects the compliance flexibility under the rule, along with transmission and pipeline capabilities and constraints, fuel market and electricity dispatch dynamics, and seasonal electricity load requirements. As described below in Section X, the results indicate that compliance with standards of performance consistent with the final BSER is readily achievable with no adverse impacts on electricity system reliability, and that impacts on retail electricity prices are modest and fall within the range of price variability seen historically in response to changes in factors such as weather and fuel supply. Further, the costs tend to decline over time as states and regulated entities take advantage of the available flexibility and expand deployment of more cost-effective measures (notably demand-side energy efficiency). The EPA considers this analysis strong confirmation of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 376 of 1275

reasonableness of the costs of the measures in the three building blocks in combination as the best system of emission

reduction. 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. h. Other combinations of the building blocks. The EPA has considered whether other combinations of the building blocks, such as a combination of building blocks 1 and 2 or a combination of building blocks 1 and 3, could be the BSER. We believe that any such combination is technically feasible and would be a “system of emission reduction” capable of achieving meaningful reductions in CO 2 emissions from affected EGUs at a reasonable cost. As with the combination of three building blocks discussed above, any combination of building blocks would achieve greater emission reductions than the individual building blocks encompassed in that combination would achieve if implemented in isolation. Further, the cost of any combination would be driven principally by the combined stringency and would remain reasonable in aggregate. Any combination of building*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 377 of 1275 blocks including building block 1 and at least one other building block would address the concern about potential “rebound effect” discussed above. Finally, there is no reason toexpect any combination of building blocks to have adverse nonair energy or environmental impacts. 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 strike down a building block, the BSER would comprise the remaining building blocks.

5. Actions under the BSER that sources can take to achieve standards of performance Based on the determination of the BSER described above, the EPA has identified a performance rate of 1290 lbs. per net MWh for affected steam EGUs and a performance rate of 780 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 378 of 1275 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 are another expression of the BSER, viewed through an individual-source lens. 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:

 Reducing its heat rate (building block 1).

 Directly investing in, or purchasing emission rate credits created as a result of, incremental generation from existing NGCC units (building block 2).

 Directly investing in, or purchasing emission rate credits created as a result of, generation from new or up-rated RE generators (building block 3).

 Reducing its utilization, coupled with direct investment in or purchase of emission rate credits representing building blocks 2

and 3 as indicated above.

 Investing in surplus emission rate reductions at other affected EGUs through the purchase of rate-based emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 379 of 1275 credits or the use of other multi-unit compliance approaches (e.g., averaging).

 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 of mass-based emission allowances or the use of other multi-unit compliance approaches (e.g., aggregation or bubbling). The EPA has determined appropriate emissions standards for the source category as a whole achievable through application of the building blocks. The wide ranges of measures included in the

BSER and available to individual sources as indicated above provide assurance that the source category as a whole can achieve standards of performance consistent with those emissions standards using components of the BSER, whether states choose to

establish emission rate-based limits or mass-based limits. The*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 380 of 1275 wide ranges of measures included in the BSER also provide

assurance that each individual affected source could achieve the standard of performance its state establishes for it using components of the BSER. Of course, sources may also employ measures not included in the BSER, to the extent allowed under the applicable state plan. 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 –- i.e., vertically integrated utilities and merchant generators; investor-owned, government-owned, and customer-owned (cooperative) utilities; and owner/operators of large, small, and single-unit fleets of generating units –- have the ability to deploy each of the building blocks in some way. In the following subsection we discuss the use of measures not in the BSER that can help sources achieve the standards of performance.

a. Use of BSER measures to achieve an emission rate-based standard. Under an emission-rate based form of performance standards, compliance is nominally determined through a comparison of the affected EGU’s emission rate to the emission rate standard. Because an emission rate computed solely based on*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 381 of 1275 measured stack emissions and measured electricity generation will not reflect the emissions-reducing impact of BSER measures

that reduce CO 2 emissions through reductions in the quantity of generation rather than through reductions in the amount of CO 2 emitted per unit of generation, a plan that imposes emission rate-based standards of performance on affected EGUs will also need to authorize a rate computation mechanism whereby affected EGUs can adjust the rate computation to account for generation

reduction measures. One mechanism that the EPA has determined to be appropriate is to include emission rate credits (ERCs) in the emission rate computations that affected EGUs perform to demonstrate compliance with an emission rate standard. This 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. We have determined that one viable way to specify ERCs – which we believe offers benefits of fungibility and ease of tracking – is to define theERCs associated with building blocks 2 and 3 as units of zeroemissions generation. As summarized below and as discussed in greater detail in section VIII and in the Rate-based Program Accounting TSD for the CPP Final Rule, the existence of a clearly feasible path for usage of ERCs ensures that emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 382 of 1275 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) Building block 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 emission rate. Examples of actions in this category are included in section V.C. below and in the GHG Mitigation Measures TSD for the CPP Final Rule. Any type of owner/operator can take advantage of this measure. (2) Building block 2. The owner/operator of an affected EGU can average the EGU’s emission rate with incremental generation from an existing NGCC unit or with ERCs issued on the basis of incremental generation from an existing NGCC unit. The owner/operator of the affected EGU accomplish this either through 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 383 of 1275 the use of ERCs. While the opportunity to acquire ERCs through common ownership of NGCC facilities 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 ERCs just as they can engage in transactions for other kinds of goods and services. In section VIII 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 –- i.e., incremental generation by an existing NGCC unit and the NGCC unit CO 2 emissions associated with that incremental generation –- is adequately monitored and that there is an adequateadministrative process for tracking credits to avoid doublecounting. In the case of ERCs related to building block 2, the monitoring criteria would generally be satisfied by standard 40 CFR part 75 monitoring. As noted above, the EPA has determined that one way to define an ERC –- which facilitates fungibility and tracking –- is to denominate each ERC in the form of a single zero-emissions

MWh. NGCC units have non-zero CO 2 emission rates, but their CO 2 emission rates are lower than the CO 2 emission rates of affected*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 384 of 1275

steam EGUs. Consistent with the fact that the BSER for affected steam EGUs reflects the opportunity to replace generation from affected steam EGUs with incremental generation from existing NGCC units at a lower, but non-zero, emission rate, incremental generation by an existing NGCC unit can qualify as the basis for issuance of ERCs, but one incremental MWh of NGCC generation

would be insufficient to serve as the basis for an ERC worth one full MWh of zero-emissions generation. The specific number of incremental MWh that an NGCC unit would need to generate in order to qualify for issuance of an ERC representing one MWh of zero-emissions generation would depend on the magnitude of the

difference between the NGCC unit’s actual emission rate and the average standard of performance for affected steam EGUs in its state –- e.g., the uniform emission rate representing the BSER for steam EGUs. Details of the computation are provided in the Rate-based Accounting TSD for the CPP Final Rule available in

the docket. 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 2 emission rate for purposes*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 385 of 1275 of demonstrating compliance with its emission rate-based standard of performance. (3) Building block 3. The owner/operator of an affected EGU can average the EGU’s emission rate with generation from new (i.e., post-2012) RE generating capacity, including both newly constructed capacity and new uprates to existing RE generating capacity, or with ERCs issued on the basis of such generation. The owner/operator of the affected EGU can accomplish this either through common ownership of the RE generating capacity, a bilateral transaction with the owner/operator of the RE generating capacity, or a transaction for ERCs through an intermediary, which could, but need not, involve an organized

market. 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 ERCs. While the opportunity to acquire ERCs through common ownership of RE generating facilities 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 ERCs just as they can engage in transactions for other kinds of goods and services.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 386 of 1275 In section VIII 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 –- i.e., generation by from qualifying new RE capacity –- is adequately monitored and that there is an adequate administrative process for tracking credits to avoid double-counting and to facilitate enforceability of emission

limits. The types of RE generating capacity used by the EPA to quantify building block 3 are zero-emitting units. Under the definition of ERCs described above, each MWh of incremental generation by qualifying new RE generating capacity therefore can qualify as the basis for issuance of an ERC representing a

full zero-emissions MWh. 310 Further details are provided in the Rate-based Program Accounting TSD for the CPP Final Rule

available in the docket. 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,

310 The possible use of types of RE generating capacity that are not necessarily zero-emitting, such as biomass, is discussed in section V.A.6. and section VIII of the preamble.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 387 of 1275 a bilateral transaction, or an intermediated transaction –- by adding the ERCs to its measured net generation when computing

its CO 2 emission rate for purposes of demonstrating compliance with its emission rate-based standard of performance. (4) Reduced generation. 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 or otherwise invests in incremental generation from existing NGCC capacity or generation from new RE generating capacity. If the owner/operator does not average any ERCs or qualifying cleaner generation into the unit’s emission rate, reducing the unit’s own generation will proportionately reduce

both the numerator and denominator of the fraction and therefore will not affect the computed emission rate. However, if the owner/operator does average ERCs or qualifying cleaner generation into the unit’s emission rate, then a proportional reduction in both the numerator and the portion of the denominator representing the unit’s measured generation will amplify the effect of the acquired ERCs in the computation, with the result that the more the unit reduces its generation, the fewer ERCs will be needed to reach a given emission rate-based*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 388 of 1275 standard of performance. All owner/operators have the ability to reduce generation, and as discussed above all also would be capable of acquiring ERCs, so all would be capable of reflecting reduced utilization in their emission rates for purposes of demonstrating compliance. (5) Emissions trading or other multi-unit compliance approaches. To the extent allowed under the relevant section 111(d) plans, the owner/operator of an affected EGU can invest in surplus emission rate reductions not needed by another affected EGU and average those reductions into its own emissionrate for purposes of demonstrating compliance with its ratebased standard of performance. A multi-unit approach without tradable credits is possible, commonly referred to as averaging. Alternatively, tradable credits could be used, reflecting an emissions trading approach. In either case, 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, we read the comment record and the discussions that occurred during the outreach process to support the prediction that such authorization will be forthcoming from virtually all states that submit plans establishing standards of performance for their affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 389 of 1275 Under an emissions trading approach, the owner/operator of the affected EGU can acquire surplus 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. 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 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. One possible form of tradable credit that could be traded among affected EGUs would be a credit denominated in the form of a single zero-emission MWh, which would be entirely fungible with the form of ERC described above by which affected EGUs could acquire the emissions-reducing benefits of activating encompassed in building blocks 2 and 3. The number of MWh that

an affected EGU with an emission rate below its standard would*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 390 of 1275 need to generate to serve as the basis for issuance of each tradable credit – or, conversely, the number of tradable credits

that a unit with an emission rate above its standard would need to acquire in order to achieve compliance – would be based on

the difference between the unit’s actual emission rate and the unit’s standard of performance established in the applicable section 111(d) plan. Details regarding these computations are included in the Rate-based Program Accounting for the CPP Final

Rule available in the docket.

b. Use of BSER measures to achieve a mass-based standard. Under a mass-based form of the standard, compliance is determined through a comparison of the affected EGU’s monitored mass emissions to a mass-based emission limit. Although a state could choose to impose specific mass-based limits that each EGU would be required to meet on a physical basis, in past instances where mass-based limits have been established for large numbers of sources it has been typical for the limit on each affected source to be structured as a requirement to periodically surrender a quantity of emission allowances equal to the

source’s monitored mass emissions. The EPA believes that section111(d) encompasses the flexibility for plans to impose massbased standards in the typical manner where the standard of performance for each affected EGU consists of a requirement to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 391 of 1275 surrender emission allowances rather than a requirement to physically comply with a unit-specific emissions cap. 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 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) Building block 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 mass emissions. Examples of actions in this category are included in section V.C. below and in the GHG Mitigation Measures TSD for the CPP Final Rule. Any type of owner/operator can take advantage of this measure. (2) Reduced generation. The owner/operator of an affected EGU can reduce its generation, thereby lowering the unit’s CO 2 mass emissions. Any type of owner/operator can take advantage of this measure. Although some action or combination of actions to increase lower-carbon generation or reduce electricity demand*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 392 of 1275 somewhere in the interconnected electricity system of which the affected EGU is a part will be required to enable electricity supply and demand remain in balance, the affected EGU does not

need to monitor or track those actions in order to use its reduction in generation to help achieve compliance with the mass-based standard. Instead, multiple participants in the interconnected electricity system will act to ensure that supply and demand remain in balance, subject to the complex and constantly changing set of constraints on operation of the system, just as those participants have routinely done for

years. 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 energy efficiency 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 393 of 1275 (3) Emissions trading or other multi-unit compliance approaches. To the extent allowed under the relevant section 111(d) plans -- as the record indicates that it will be -- the owner/operator of an affected EGU can invest in surplus emission reductions not needed by another affected EGU and can aggregate those reductions with its own emissions for purposes of demonstrating compliance with its mass-based standard of performance. This could be done through either approaches using

tradable mass-based emission allowances or other multi-unit compliance approaches, which in this case would consist of aggregation or bubbling of emission limits. In either case, 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. Under an emissions trading approach, the owner/operator of the affected EGU 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 394 of 1275 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.

6. Use of non-BSER measures to achieve standards of performance

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 measuresthat are included in the BSER; thus, the existence of these nonBSER 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 therefore provide*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 395 of 1275 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 2 emitted per MWh of generation from the set of affected EGUs or reduce the amount of generation, and therefore

associated CO 2 emissions, from the set of affected EGUs. However, the manner in which the various non-BSER measures would help

individual affected EGUs meet their individual standards of performance varies according to the type of measure and the type of standard of performance –- i.e., whether the standard is

emission rate-based or mass based. In general, a non-BSER measure that reduces the amount of

CO 2 emitted per MWh of generation at an affected EGU will reduce

the amount of CO 2 emissions monitored at the EGU’s stack (assuming the quantity of generation is held constant). Measures of this type can help the EGU meet either an emission rate-based or mass-based standard of performance.

Other non-BSER measures do not reduce an affected EGU’s CO 2 emission rate but rather facilitate reductions in CO 2 emissions by reducing the amount of generation from affected EGUs. Under a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 396 of 1275 mass-based standard, the collective reduction in emissions from

the set of affected EGUs is reflected in the collective

monitored emissions from the set of affected EGUs. An individual EGU that reduces its generation and emissions will be able to use the measure to help achieve its mass-based limit. Individual EGUs that do not reduce their generation and emissions will be able to use the measure, if the relevant section 111(d) plans provide for allowance trading, by purchasing emission allowances no longer needed by EGUs that have reduced their emissions. 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. For some non-BSER measures, each MWh of incrementalgeneration produced by the measure or each MWh of fossil fuelfired generation avoided by the measure could qualify as the basis for issuance of an ERC representing a full zero-emissions MWh, similar to building block 3. For other non-BSER measures, more than one MWh of incremental generation would be required toqualify for the basis of an ERC representing a full zeroemissions MWh, similar to building block 2. Affected EGUs could*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 397 of 1275 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 2 emitted per MWh of generation,

and the second set discussed includes measures that can reduce

CO 2 emissions by reducing the amount of generation from affected EGUs. In some cases, considerations related to use of these measures for compliance is discussed below in section VIII on state plans. The EPA notes that this is not an exhaustive list of non-BSER measures that could be employed to reduce CO 2 emissions from affected EGUs.

a. Non-BSER measures that reduce CO 2 emissions per MWh generated. In the June 2014 proposal, the EPA discussed several potential

measures that could reduce CO 2 emissions per MWh generated at affected EGUs but that were not proposed to be part of the BSER. The measures discussed included heat rate improvements at affected EGUs other than coal-fired steam EGUs; fuel switching to natural gas at affected EGUs, either completely (conversion) or partially (co-firing); and carbon capture and storage by affected EGUs. One reason for not proposing to consider these measures to be part of the BSER was that they were more costly

than other measures. Another reason was that the emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 398 of 1275 reduction potential was limited compared to the potential available from the measures that were proposed to be included in the BSER. However, we also noted that circumstances could exist where these measures could be sufficiently attractive to deploy, and that the measures could be used to help affected EGUs

achieve emission limits consistent with the BSER. 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 representative of the BSER, as discussed above. Further discussion of these measures is also provided in the GHG Mitigation Measures TSD for the CPP Final Rule.(1) Heat rate improvement at affected EGUs other than coalfired steam EGUs. 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 reductions available from heat rate improvements at coal-fired steam EGUs are much larger than the potential CO 2 reductions*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 399 of 1275 available from heat rate improvements at other types of EGUs, and comments offered no persuasive basis for reaching a different conclusion. Nevertheless, we recognize that there may be instances where an owner/operator finds heat rate improvement to be an attractive option at a particular non-coal-fired affected EGU, and nothing in the rule prevents the owner/operator from implementing such a measure and using it to help achieve a standard of performance. (2) Carbon capture and storage at affected EGUs. Another approach for reducing CO 2 emissions per MWh of generation from affected EGUs is the application of carbon capture and storage (CCS) technology. Consistent with the June 2014 proposal, we are determining that use of full or partial CCS technology should not be part of the BSER for existing EGUs because it would be more expensive than the measures determined to be part of the BSER, particularly if applied broadly to the overall source category. At the same time, we note that retrofit of CCS technology may be a viable option at some individual facilities, particularly where the captured CO 2 can be used for enhanced oil recovery (EOR). For example, construction of one CCS retrofit application with EOR has already been completed at a unit at the Boundary Dam plant in Canada, and construction of another CCS retrofit application with EOR is underway at the W.A. Parish*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 400 of 1275 plant in Texas. We expect the costs of CCS to decline as implementation experience increases. CO 2 emission rate reductions achieved through retrofit of CCS technology would be available to help affected EGUs achieve emission limits consistent with

the BSER. (3) Fuel switching to natural gas at affected EGUs. In the proposal we discussed the opportunity to reduce CO 2 emissions at an individual affected EGU by switching fuels at the EGU,particularly by switching from coal to natural gas. Most coalfired EGUs could be modified to burn natural gas instead, and the potential CO 2 emission reductions from this measure are large – approximately 40 percent in the case of conversion from 100 percent coal to 100 percent natural gas, and proportionately smaller for partial co-firing of coal with natural gas. The primary reason for not considering this measure part of the BSER, both at proposal and in this final rule, is that it is more expensive than other BSER measures. In particular, combusting natural gas in a steam EGU is less efficient and generally more costly than combusting natural gas in an NGCC unit. For the category as a whole, CO 2 emissions can be achieved far more cheaply by combusting additional natural gas in currently underutilized NGCC capacity and reducing generation*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 401 of 1275 from coal-fired steam EGUs (building block 2) than by combusting natural gas instead of coal in steam EGUs. 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 certaincircumstances, such as when a unit must meet tighter unitspecific 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 2 emission reductions achieved in these situations are available to help achieve emission

limits consistent with the BSER. (4) Fuel switching to biomass at affected EGUs. Some affected EGUs may seek to reduce their CO 2 emission rates by cofiring qualifying biomass with fossil fuels. As discussed in section VIII below, the EPA recognizes that some biomass-derived fuels can play an important role in CO 2 emissions reduction strategies. The EPA expects to recognize the biogenic CO 2 emissions and climate policy benefits of waste-derived and certain forest- and agriculture-derived industrial byproduct feedstocks when considering state plans, based on the conclusions supported by a variety of technical studies. In addition, the EPA expects that states’ reliance on sustainably*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 402 of 1275 derived agriculture- and forest-derived feedstocks may also be an approvable element of their state plans. 311 As with the other non-BSER measures discussed in this section, the EPA expects that use of biomass may be economically attractive for certain individual sources even though on a broader scale it would likely be more expensive or less achievable than the measures determined to be part of the BSER. A state can propose qualifying biomass feedstocks and the proposed treatment of biogenic CO 2 emissions in its plan. State plans must include analysis supporting how proposed qualifying feedstocks or feedstock categories are considered appropriate as a CO 2 emission mitigation approach as well as the proposed treatment of biogenic CO 2 emissions (i.e., the proposed level of biogenic CO 2 emissions from use of the biomass feedstock that would not be counted when demonstrating compliance with emission limits consistent with the BSER). The EPA would review the appropriateness and basis for such determinations in the course of its review of a state plan. (5) Waste heat-to-energy conversion at affected EGUs.

Certain affected EGUs in urban areas or located near industrial facilities with needs for thermal energy may be able capture

311 For a discussion of considerations concerning biomass in state plans, see section VIII.G.1.a.(2)(c)(i) of the preamble.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 403 of 1275 some of the waste heat from their electricity generation processes and use it to create useful thermal output, thereby engaging in a form of combined heat and power (CHP) production sometimes referred to as topping-cycle cogeneration. While the set of affected EGUs in locations making this measure feasible may be limited, where the measure is feasible the potential CO 2 emission rate improvements can be substantial, because conversion of a conventional EGU to CHP configuration can increase the efficiency with which fuel is converted to useful energy by 25 percent or more. The final rule allows an owner/operator applying CHP technology to an affected EGU to account for the increased efficiency by counting the useful thermal output as additional MWh of generation, thereby lowering the unit’s computed emission rate and assisting with achievement of an emission rate-based standard of performance. (The EPA notes that unless the unit also reduced its fuel usage, the addition of the capability to capture waste heat and produce useful thermal output would not reduce the unit’s mass emissions and therefore would not help the unit achieve a mass-based standard of performance.)

b. Non-BSER measures that reduce CO 2 emissions by reducing fossil fuel-fired generation. A second group of non-BSER measures has the potential to reduce CO 2 emissions from affected EGUs by*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 404 of 1275 reducing the amount of generation from those EGUs. As discussed above, under a section 111(d) plan with mass-based standards of performance, no special action is required to enable measures of this nature to help the source category as a whole and individual affected EGUs achieve their emission limits, because

the CO 2 -reducing effects are captured in monitored stack emissions. However, under a section 111(d) plan with rate-based standards of performance, some form of crediting such as the ERC mechanism described earlier is necessary in order to enable measures of this nature to help the source category as a whole

and individual affected EGUs achieve the emission limits. (1) Demand-side energy efficiency. One of the major approaches available for achieving CO 2 emission reductions from the utility power sector is demand-side energy efficiency. In the June 2014 proposal, the EPA identified demand-side energy efficiency as one of the four proposed building blocks for the BSER. We continue to believe that significant emission reductions can be achieved by the source category through use of such measures at reasonable costs. In fact, we believe that the potential emission reductions from demand-side energy efficiency rival those from building blocks 2 and 3 in magnitude, and that demand-side energy efficiency will represent an important component of state plans, particularly in instances where a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 405 of 1275 state prefers to develop a plan reflecting the state measures approach discussed in section VIII below. We also expect that many sources would be interested in including demand-side energy efficiency in their compliance strategies to the extent permitted, and received comment that it should be permitted. For the reasons discussed in section V.A.3.e. above, the EPA has determined not to include demand-side energy in the BSER in this final rule. However, the final rule authorizes generation avoided through investments in demand-side energy efficiency to serve as the basis for issuance of ERCs in defined circumstances. In section VIII below, the EPA sets out the minimum criteria that must be satisfied for generation andissuance of a valid ERC based upon implementation of new demandside EE programs. Those criteria generally concern assuring that the physical basis for the ERC -– in this case, generation avoided through implementation of demand-side EE measures –- is adequately monitored and that there is an adequateadministrative process for tracking credits to avoid doublecounting and to facilitate enforceability of emission limits. The particular considerations related to evaluation, measurement, and verification of demand-side EE programs are

also discussed in section VIII.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 406 of 1275 Through their authority over legal requirements such as building codes, states have the ability to drive certain types of demand-side energy efficiency 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 below. (2) New or up-rated nuclear generating capacity. 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., 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 2 emissions, and the continued commitment of the owner/operators to completion of the units is essential in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 407 of 1275 order to realize that result. Accordingly, a section 111(d) plan may rely on ERCs issued on the basis of generation from these units and other new nuclear units. For the same reason, a plan may rely on ERCs issued on the basis of generation from up-rates to the capacity of existing nuclear units. The plan provisions to accommodate ERCs for generation from new and uprated nuclear capacity would be similar to the plan provisions necessary to accommodate ERCs issued on the basis of generation from new RE generating capacity (i.e., building block 3), which is also zero-emitting. These provisions are discussed in section VIII

below. (3) Zero-emitting RE generating technologies not reflected in the BSER. The range of available zero-emitting renewable energy 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 408 of 1275 equally capable of replacing generation from affected EGUs and thereby reducing CO 2 emissions. Further, as with any technology, there are likely to be certain circumstances where the costs of these technologies are more attractive relative to alternatives, making the technologies likely to be deployed to some extent. Indeed, distributed solar is already being widely deployed in much of the United States and offshore wind, while still unusual in this country, has been extensively deployed in some other parts of the world. We expect innovation in RE generating technologies to continue, making such technologies even more attractive over time. A section 111(d) plan may rely on ERCs issued on the basis of generation from new and uprated installations of these technologies. The plan provisions to accommodate ERCs issued on the basis of generation from these RE generating technologies again would be similar to the plan provisions necessary to accommodate ERCs issued on the basis of generation from other RE generating technologies (building block 3). (4) Non-zero-emitting RE generating technologies. Generation from new or expanded facilities that combust qualifying biomass or biogenic portions of municipal solid waste (MSW) to produce electricity can also replace generation from*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 409 of 1275 affected EGUs and thereby reduce CO 2 emissions. 312 While the EPA believes it is reasonable to consider generation from these technologies to be forms of RE generation, the fact that the technologies produce stack emissions containing CO 2 means that a section 111(d) plan seeking to permit use of such generation to serve as the basis for issuance of ERCs must include appropriate consideration of feedstock characteristics and climate policy benefits. Again, as discussed in section VIII below, the EPA expects to recognize the biogenic CO 2 emissions and climatepolicy benefits of waste-derived feedstocks and certain forestand agriculture-derived industrial byproduct feedstocks when considering state plans. The EPA also expects that states’ reliance specifically on sustainably-derived agriculture- and forest-derived feedstocks may also be an approvable element of their state plans. The EPA and many states have recognized the importance of integrated waste materials management strategies that emphasize a hierarchy of waste prevention and all other productive uses of waste materials to reduce the volume of disposed waste materials. Because it is likely that more than

312 The EPA and many states have recognized the importance of integrated waste materials management strategies that emphasize a hierarchy of waste prevention and all other productive uses of waste materials to reduce the volume of disposed waste materials (see section VIII for more discussion of waste to energy strategies).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 410 of 1275 one MWh of incremental generation from these technologies would be required as the basis qualifying for the issuance of an ERC worth a full MWh of zero-emitting generation, the minimum requirements to accommodate ERCs issued on the basis of generation from these technologies would be similar to the plan provisions necessary to accommodate ERCs issued on the basis of incremental generation from existing NGCC units (building block 2), supplemented by appropriate provisions to address special

characteristics of the feedstocks. (5) Waste heat-to-electricity conversion at non-affected facilities. Industrial facilities that install equipment to capture waste heat and then use the waste heat to generate electricity –- a form of combined heat and power (CHP) production sometimes referred to as bottoming-cycle cogeneration –- can produce generation that replaces generation from affected EGUs and thereby reduces CO 2 emissions. A section 111(d) plan may rely on ERCs issued on the basis of generation of this nature provided that the facility does not generate and sell sufficient electricity to qualify as a new EGU for purposes of section 111(b) and is not covered under section 111(d) for anothersource category. This form of CHP can be considered zeroemitting to the extent that the waste heat would have been produced by the industrial process anyway. To the extent that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 411 of 1275 the section 111(d) plan includes appropriate provisions for establishing that the heat input truly is waste heat, each MWh of incremental generation from this form of CHP could serve as

the basis for issuance of an ERC worth a full MWh of zeroemitting generation similar to an ERC issued on the basis of building block 3. In order to permit ERCs issued on the basis of generation from facilities where the waste heat input is supplemented by fossil fuel input, the plan would need to include appropriate provisions for establishing the number of incremental MWh that would be generated in order to serve as the

basis for issuance of each ERC worth one full MWh of zeroemitting generation, similar to the plan provisions required to support an ERC issued on the basis of building block 2. (6) Reduction in transmission and distribution line losses. 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 2 emissions. The opportunity for improvement is large because, on average, line losses account for approximately seven percent of all*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 412 of 1275 electricity generation. The EPA recognizes that, in general, only the owner/operators of the transmission and distribution facilities have the ability to undertake line loss reduction investments, and that merchant generators may have little opportunity to engage a contractor to pursue such opportunities on a bilateral basis. Nevertheless, for entities that do have the opportunity to make such investments, generation avoided through investment that reduces transmission and distribution line losses may serve as the basis for issuance of ERCs that in turn can be used by affected EGUs. This avoided generation is analogous to the generation avoided through demand-side energy efficiency described above, and each MWh of avoided generation

could serve as the basis for creation of an ERC worth one full zero-emitting MWh of generation. The section 111(d) would need to include appropriate provisions for quantifying and verifying

the avoided MWh associated with the transmission and

distribution investments. 7. Severability. 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. Each building block is a feasible and demonstrated means of reducing CO 2 emissions from the utility power sector*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 413 of 1275 that can be implemented independently of the other building blocks. As discussed in sections V.C. through V.E. below, we have determined that each building block is independently of reasonable cost whether or not the other building blocks are applied, and that alternative combinations of the building blocks are likewise of reasonable cost, and we have determined reasonable schedules and stringencies for implementation of each building block independently, based on factors that generally do not vary depending on the implementation of other building

blocks. Further, 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, 313 although less than the combination of all three building blocks. No combination of the building blocks would lead to adverse non-air environmental or energy impacts or impose a risk to the reliability of electricity supplies. In the event that a court should strike down any individual building block used to compute the emissions standards and state goals set forth in this rule, the standards and state goals can be recomputed on the basis of the remaining building blocks. All

313 This conclusion would not extend to a BSER comprising solely building block 1 because of the possibility of rebound effects discussed earlier.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 414 of 1275 of the data and procedures necessary to determine recomputed state goals using any combination of the building blocks are set forth in the Final Rule Goal Computation TSD available in the

docket. B. Legal Discussion of Certain Aspects of the BSER 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) EPA’s basis that building blocks 2 and, 3, and 4 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 controlling the design or operation of the affected source itself ’s own production processes or methods or because they are dependent on actions by entities other than the affected source; (2) the EPA’s basis for including trading or averaging as a component of BSER; (3) the EPA’s basis for including reduced generation as a component of the BSER; (4) the EPA’s authority to determine the BSER; (5) the consistency between the EPA’s identification of the BSER for

this rule for CO 2 emissions from existing affected EGUs and the BSER for the rules the EPA is promulgating at the same time for

CO 2 emissions from new or modified affected EGUs; (6) the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 415 of 1275 relationship between an affected EGU’s implementation of building blocks 2 and 3 and CO 2 emissions reductions; and (7) the approach to subcategorization; and (8) reasons why, contrary to assertions by commenters, this rule is within the EPA’s statutory authority and does not represent what the U.S. Supreme Court described as “an enormous and transformative expansion in [the] EPA’s regulatory authority”. 314 1. Building blocks 2 and 3 as a “system of emission reduction” a. Overview. As we explain above, the performance standards for emissions that we include in this rule’s emissions 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 (renewable energy) cannot, as a legal matter, be considered to be 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 performance standards must be based on, and therefore BSER must be limited to, methods for emissions control that the owner/operator of the affected source can integrate into the design or operation of the source itself, and that cannot be based on actions taken beyond the source or actions involving

314 Util. Air Regulatory Group v. EPA , 134 S. Ct. 2427, 2444 (2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 416 of 1275 third-party entities. 315 For these reasons, these commenters argue that the phrase “system of emission reduction” cannot be interpreted to include building blocks 2 and 3. We disagree with these comments. 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 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

315 See, e.g., comments by UARG at 6-7 (“Standards promulgated under section 111 must be source-based and reflect measures that the source’s owner can integrate into the design or operation of the source itself. A standard cannot be based on actions taken beyond the source itself that somehow reduce the source’s utilization.”); comments by UARG at 31 (the building blocks other than building block 1 take a “’beyond-the-source’ approach” and “impermissibly rely on measures that go beyond the boundaries of individual affected EGUs and that are not within the control of individual EGU owners and operators”); comments by UARG at 33 (the “system” of emission reduction “can refer only to reductions resulting from measures that are incorporated into the source itself;” section 111 is “designed to improve the emissions performance of new and existing sources in specific categories based on the application of achievable measures implemented in the design or production process of the source at reasonable cost.”); comments by American Chemistry Council et al. (“Associations”) at 60-61 (EPA’s proposed BSER analysis is unlawful because it “looks beyond the fence line of the fossil fuel-fired EGUs that are the subject of this rulemaking;” “the standard of performance must ... be limited to the types of actions that can be implemented directly by an existing source within [the appropriate] class or category.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 417 of 1275 broad and, under Chevron step 1, 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. The measures in building blocks 2 and 3, which include these types of actions,

enable the affected EGUs to achieve their emission limits due to the unique characteristics of the utility power sector. For these reasons, we envision a “system of emission reduction” – as defined under CAA section 111(a)(1) and applied under CAA section 111(d)(1) -- as a big toolbox, which includes the measures in building blocks 2 and 3. It should be recalled, however, that CAA section 111 also requires that we determine that these measures are “adequately demonstrated” and represent the “best” system of emission reduction in order to serve as the basis for the emission reduction requirements.

Our Chevron step 1 interpretation that the “system of emission reduction” is broad enough to include the measures in building blocks 2 and 3 is supported by the following: the phrase “system of emission reduction” is consistent with the “catch-all” nature of CAA section 111(d)(1), which is designed*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 418 of 1275 to cover a range of source categories and air pollutants; the legislative history of CAA section 111(d)(1) and (a)(1), which indicates Congress’s intent to give the EPA broad discretion in determining the basis for CAA section 111 control requirements, particularly for existing sources, and Congress’s intent to

authorize the EPA to consider measures that could be carried out by parties other than the affected sources; and comparisons to other provisions of the CAA that give the EPA similar authority to consider such measures, and comparisons to other provisions that clearly narrow the field of measures to be considered. Finally, we note that contrary to arguments by commenters, no other provisions of CAA section 111 suggest that the phrase “system of emission reduction” must be limited to measures that the source’s owner can integrate into the design or operation of

the affected source itself.. To the extent the phrase “system of emission reduction” is ambiguous, the EPA has discretion under Chevron step 2 to interpret it to include building blocks 2 and 3, for the reasons stated above, as well as 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 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 419 of 1275 emissions. (iii) Interpreting the phrase “system of emission reduction” to incorporate building blocks 2 and 3 is consistent with (a) other provisions in the CAA, including the acid rain provisions in Title IV and the SIP provisions in CAA section 110, along with the EPA’s regulations implementing the CAA SIP requirements concerning interstate transport and regional haze,

each of which is based on at least some of the same measures included in building blocks 2 and 3; (b) prior EPA action under CAA section 111(d), including the 2005 Clean Air Mercury Rule, which is based on some of the same measures in building blocks 2 and 3; (c) the various provisions of the CAA that authorize emissions trading, because emissions trading entails a source meeting its emission limitation based on the actions of another entity; and (d) the pollution prevention provisions of the CAA, which make clear that a primary goal of the CAA is to encourage federal and state actions that reduce or eliminate, through any measures, the amount of pollution produced at the source. (iv) Most broadly, interpreting the phrase “system of emission reduction” to give the EPA a big toolbox that includes building blocks 2 and 3 to reduce emissions is consistent with Congress’s intention to address urgent environmental problems and to be precautionary in protecting public health and welfare against risks, as well as Congress’s expectation that American industry*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 420 of 1275 would be able to develop the innovative solutions necessary to protect public health and welfare. b. System of emission reduction as a big toolbox under Chevron Step 1. (1) Plain meaning of “system of emission reduction”. CAA section 111(d)(1) and (a)(1) make clear that because the purpose of the “system of emission reduction” is to serve as the basis for the emission limitation, and because the emission limitation must be “achievable” by the source, the “system of emission reduction” must be of a type that allows the source to achieve its emission

limitation. The term “system” is not defined in the CAA. As a result, that term should be given its ordinary, everyday meaning, which is “a set of things working together as parts of a mechanism or interconnecting network; a complex whole.” 316 With this definition, the phrase “system of emission reduction” takes a broad meaning: a set of things that work together to reduce emissions. In light of its context, this phrase carries an important limitation: because the emission limitation must be

316 Oxford Dictionary of English (3rd ed.) (published 2010, online version 2013) http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/ 9780199571123.001.0001/acref-9780199571123

. See The American College Dictionary (C. L. Barnhart, ed. 1970) at [X](“an assemblage or combination of things or parts forming a complex or unitary whole”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 421 of 1275 achievable through the application of the system of emission reduction, the system must be limited to things that can be implemented by the sources themselves, that is, as a practical matter, to actions taken by the owners or operators of the sources. Thus, actions that the owners/operators may take to achieve an applicable emission limitation qualify as a system of

emission reduction. 317 In contrast, actions that the state could take that would have the effect of reducing emissions from the source category, but that are beyond the ability of the affected sources’ owners/operators to take or control, would not qualify as a system of reduction for this purpose. 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

317 Some commenters read the proposed rulemaking as taking the position that the phrase “system of emission reduction” includes anything whatsoever that reduces emissions, and criticized that interpretation as too broad. See UARG comment. In this final rule, we agree that the phrase should be limited to exclude actions beyond the ability of the owners/operators to take.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 422 of 1275 that owners/operators of affected EGUs can take to implement the

measures. It should be noted that, although we do not need to determine the overall scope of the “system of emission reduction,” other limitations may also apply. For example, it is doubtful that payments by a source to a governmental entity to fund some sort of pollution prevention or emission control program would qualify as a system of emission reduction because the source may not be able to assure that the governmental entity will take the requisite action. A change in governmental policy could interfere with the implementation of the government program and, under those circumstances, the source would be unable to achieve the required degree of emission limitation. For purposes of this final rule, however, it is not necessary to enumerate all of the types of methods of emission reduction 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” because, as noted, 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 423 of 1275 (2) Other indications that the BSER provisions are a big toolbox. The EPA’s plain meaning interpretation of the BSER provisions in CAA section 111(d)(1) and (a)(1) as a big toolbox that is 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) “Catch-all” nature of CAA section 111(d)(1). First, the “catch-all” nature of CAA section 111(d)(1) supports interpreting BSER as a big toolbox 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, the 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 statutory 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. 318

318 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations implementing CAA section 111(d)).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 424 of 1275 Congress enacted CAA section 111(d) to cover this third category of air pollutants and, in this sense, the Congress designed it to be a “catch-all” -- it would apply to any air pollutants that were not otherwise regulated as toxics or NAAQS pollutants. 319 This would include air pollutants that the EPA might later, when more information became available, designate as NAAQS or hazardous air pollutants, as well as air pollutants that Congress may not have been aware of at the time. 320 In addition, the indications are that Congress expected CAA section 111(d) to be a significant source of regulatory activity, by some measures, more active than CAA section 112. This is evident because Congress expected that CAA section 111(d) would cover more air pollutants than either CAA section 109/110 (criteria pollutants) or CAA section 112 (hazardous air pollutants). 321 In

319 See Sen. Rep. No. 91-1196, p. 20 (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 [ i.e., the bill’s version of CAA section 112] could be established under section 114 [ i.e. , the bill’s version CAA 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.”). 320 See Sen. Rep. No. 91-1196, p. 20 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420. 321 See Sen. Rep. No. 91-1196, pp. 9; 18-20, 1970 CAA Legis. Hist. at 418-20. The Senate Committee Report identified 14 substances as subject to the provision that became section 111(d), four substances as hazardous air pollutants that would be regulated under the provision that became section 112, and 5 substances as criteria pollutants that would be regulated under*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 425 of 1275 addition, in the 1990 CAA Amendments, Congress enacted CAA section 129 to achieve emission reductions from a major source category, solid waste incinerators, and established CAA section 111(d) as the basic mechanism for that provision. The EPA subsequently promulgated a number of CAA section 129/111(d) rulemakings. 322 Finally, it should be noted that Congress designed CAA section 111(d) to cover a wide range of source categories – including any source category that the EPA identifies under subsection 111(b)(1)(A) as meeting the criteria of, in general, causing or contributing significantly to air pollution that may reasonably be anticipated to endanger public health or welfare -- along with the wide range of air pollutants.Because Congress designed CAA section 111(d) as a “catchall” provision that covers a wide range of air pollutants -- including ones that Congress may not have been aware of at the

the provisions that became sections 109-110 (and more “as knowledge increases”). In particular, the Report recognized that in particular, relatively few air pollutants may qualify as hazardous air pollutants, but that other air pollutants that did not qualify as hazardous air pollutants would be regulated under what became section 111(d). 322 See, e.g. , Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Hospital/Medical/Infectious Waste Incinerators, 62 Fed. Reg. 48,348, 48359 (Sept. 15, 1997); Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units, 65 Fed. Reg. 75338, 75341 (Dec. 1, 2000).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 426 of 1275 time it enacted the provision –- and a wide range of industries, it is logical that Congress intended that the EPA have broad discretion in determining the basis for emission limitations under CAA section 111(d), and that the BSER provision, as applied to CAA section 111(d), be broad-based so that it could accommodate this diversity. (b) Legislative history of CAA section 111. (i). Breadth of “system of emission reduction.” The legislative history of CAA section 111(d) and the term “standard of performance,” which includes the phrase “best system of emission reduction ... adequately demonstrated,” underscores the breadth that the Congress intended for the basis of CAA section 111(d) rulemaking. The version of CAA section 111(d)(1) that the 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. Therefore, CAA section 111(d)(1), as it read in 1970, allowed the EPA broad discretion in determining the basis for the emission standards.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 427 of 1275 For new sources, CAA section 111(b)(1)(B), as enacted in the 1970 CAA Amendments (and as it largely still reads), required the EPA to promulgate “standards of performance,” and defined that term, much like the present definition, as emission standards based on the “best system of emission reduction ... adequately demonstrated.” This quoted phrase was not included in either the House or Senate versions of the provision, and, instead, was added during the joint conference between the House and Senate. 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.” 323 The Senate bill, S. 4358, would have established “Federal standards of performance for new sources,” which, in turn, were to “reflect the greatest degree of emission control which the Secretary determines to be achievable through application of the latest available control technology, processes, operating methods, or other alternatives. ” 324 The Senate Committee Report explains that “performance standards

323 H.R. 17255, § 5, 1970 CAA Legis. Hist. at 921-22. The reference to “Secretary” was to the Secretary of Health Education and Welfare, which, at the time, was the agency with responsibility for air pollution regulations. 324 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 428 of 1275 should be met through application of the latest available emission control technology or through other means of preventing or controlling air pollution .” 325 This Report further elaborates that the term “standards of performance” -- refers to the degree of emission control which can be achieved through process changes, operation changes, direct emission control, or other methods . The Secretary should not make a technical judgment as to how the standard should be implemented. He should determine the achievable limits and let the owner or operator determine the most economic, acceptable technique to apply. 326 Thus, the Senate bill clearly envisioned that standards of performance would not be based on a particular technology or even a particular method to prevent or control air pollution. This vision contrasted with the House bill, which would have restricted performance standards to economically feasible

technical controls. Following the House-Senate Conference, the enacted version of the legislation defined a “standard of performance” to mean 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. 327

325 S. Comm. Rep. No. 91-1196 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 415-16 (emphasis added). 326 Sen. Rep. No. 91-1196, pp. 15-16 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 415-16 (emphasis added). 327 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis added).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 429 of 1275

While the term “system” was not discussed in the Conference Report or discussed in either chamber during the debates over passage of the Conference agreement, the final text clearly blends the broad spirit of S. 4358 (which required the “latest available control technology, processes, operating methods, or other alternatives”) with the cost concerns identified in H.R. 17255 (which required consideration of “economic feasibility” when establishing federal emission standards for new stationary sources). The legislative history, therefore, confirms that the term “system” should be given its ordinary and broad meaning. The 1977 CAA Amendments signaled, for the most part, an ideological shift in CAA section 111’s approach for new sources. The 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.’ This means that new sources may not comply merely by burning untreated fuel, either oil or

coal.” 328 This change stemmed in part from Congress’s concern over the shocks that the country experienced during the 1973-74 Arab Oil Embargo, which led Congress to revise CAA section 111

328 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 2659.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 430 of 1275 to “encourage and facilitate the increased use of coal, and to reduce reliance (by new and old sources alike), upon petroleum to meet emission requirements.” 329 Imposing a new technological requirement (along with a percentage reduction requirement) under CAA section 111 was designed to “force new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for use in existing sources where it is harder to control emissions and where low-sulfur fuel is needed for compliance.” 330 Despite these changes with respect to new sources, the 1977 CAA Amendments further reinforce the notion that with respect to existing sources, the BSER was never intended to be narrowly applied. In 1977, Congress changed CAA section 111(d)(1) to require that states adopt “standards of performance” and made clear that such standards were to be based on the ”best system of continuous emission reduction ... adequately demonstrated,” 331 but generally maintained the breadth of that term. Although Congress inserted the word “continuous” into the phrase, Congress explained that “standards in the Section 111(d) state plan would be based on the best available means (not necessarily

329 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 2659. 330 New Stationary Sources Performance Standards; Electric Utility Steam Generating Units , 44 Fed. Reg. 33580, 33581-33582 (June 11, 1979). 331 CAA section 111(a)(1)(C) under the 1977 CAA Amendments.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 431 of 1275 technological) for categories of existing sources to reduce

emissions.” 332 This was intended to distinguish existing source standards from new source standards, for which “the requirement for [BSER] has been more narrowly redefined as best technological system of continuous emission reduction.” 333 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.” Further, nothing in the 1990 CAA Amendments or their legislative history indicates that Congress intended to impose new limits on the types of systems of emission reduction that could be considered under CAA section 111(d)(1) and (a)(1). In this manner, the 1990 CAA Amendments further reinforce the breadth and flexibility of the “system of emission reduction.” For these reasons, the 1970, 1977, and 1990 legislative history confirms the breadth of the term, “system of emission

332 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 2662 (emphasis added). Congress also endorsed the EPA’s practice of establishing “emission guidelines” under CAA section 111(d). See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 2662 (“The Administrator would establish guidelines as to what the best system for each such category of existing sources is. However, the state would be responsible for determining the applicability of such guidelines to any particular source or sources.”). 333 Sen. Muskie, Sen. Consideration of the H.R. Conf. Rep. No. 95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 432 of 1275 reduction,” and supports the EPA’s interpretation in this rule that the term is sufficiently broad to encompass building blocks

2 and 3. (ii). Reliance on actions taken by other entities. 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 “system of emission reduction” must not include actions taken by entities

other than the affected sources. 334

334 See, e.g., comments by UARG at 31 (the building blocks other than building block 1 take a “’beyond-the-source’ approach” and “impermissibly rely on measures that go beyond the boundaries of individual affected EGUs and that are not within the control of individual EGU owners and operators”); comments by American Chemistry Council et al. (“Associations”) at 60-61 (EPA’s*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 433 of 1275 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.” 335 Precombustion cleaning or treatment reduces the amount of sulfur in the fuel, which means that the fuel can be

combusted with fewer SO 2 emissions, and that in turn means that the source can achieve a lower emission limit. Congress understood that these fuel cleaning techniques would not necessarily be accomplished at the affected source and, in revising CAA section 111(a)(1), wanted to ensure that such techniques would not be overlooked. For example, the 1977 House Committee report indicates that an assessment of the best technological system of continuous emission reduction for fossil fuel-fired power plants would include off-site or third-party pre-combustion techniques for reducing emissions at the source (“ e.g. , various coal-cleaning technologies such as solvent

proposed BSER analysis is unlawful because it “looks beyond the fence line of the fossil fuel-fired EGUs that are the subject of this rulemaking;” “the standard of performance must ... be limited to the types of actions that can be implemented directly by an existing source within [the appropriate] class or category.”). 335 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA section 111(a)(7).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 434 of 1275 refining, oil desulfurization at the refinery ”). 336 Thus, the standard of performance reflecting the best technological system implementable by an affected source could be based, in part, on technologies used at off-site facilities owned and operated by third-parties. 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 part of the best system of emission reduction for sulfur dioxide reductions promulgated under the 1970 CAA Amendments), and in fact, the EPA’s regulations promulgated under the 1990 CAA Amendments have continued to

336 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 2655 (emphasis added). Generally speaking, coal cleaning activities also are conducted by third parties. For instance, EPA recognized in a regulatory analysis of new source performance standards for industrial-commercial-institutional steam generating units that the technology “requires too much space and is too expensive to be employed at individual industrial-commercial-institutional steam generating units.” U.S. EPA, Summary of Regulatory Analysis for New Source Performance Standards: Industrial-Commercial-Institutional Steam Generating Units of Greater than 100 Million Btu/hr Heat Input , EPA-450/3-86-005, p. 4-4 (June 1986).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 435 of 1275 impose standards of performance that are based on third-party coal cleaning. 337 (c) Consistency of a broad interpretation of CAA section 111 with the structure of CAA. Interpreting CAA section 111(d)(1) and (a)(1) to grant broad authority to the EPA to determine the basis for the standards of performance is in keeping with how Congress structured related provisions of the CAA, particularly in the 1970 CAA Amendments, 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

337 40 C.F.R. § 60.49b(n)(4); see also Amendments to New Source Performance Standards (NSPS) for Electric Utility Steam Generating Units and Industrial-Commercial-Institutional Steam Generating Units; Final Rule , 72 Fed. Reg. 32742 (June 13, 2007).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 436 of 1275 pollutants and select the standards. Under CAA section 110, Congress required the states to submit to the EPA state implementation plans (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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 437 of 1275 determining the standards. 338 By and large, Congress left these provisions intact in the 1977 CAA Amendments. 339340 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 section 111(d) requirements are broadly phrased, include procedural requirements, 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

338 By comparison, under the 1990 CAA Amendments, Congress substantially transformed CAA section 112 to be significantly more prescriptive in directing EPA rulemaking, which reflected Congress’s increased knowledge of hazardous air pollutants and impatience with the EPA’s progress in regulating. 339 In the 1977 CAA Amendments, Congress applied the same broad drafting approach to the stratospheric ozone provisions it adopted in CAA sections 150-159. There, Congress authorized the EPA to determine whether, “in the Administrator’s judgment, any substance, practice, process, or activity may reasonably be anticipated to affect the stratosphere, especially ozone in the stratosphere, and such effect may reasonably be anticipated to endanger public health or welfare,” and then directed the EPA, if it made such a determination, to “promulgate regulations respecting the control of such process practice, process, or activity....” CAA section 157(a). This provision does not further specify requirements for the regulations. 340 On the other hand, in those instances in which Congress had a clear idea as to the emission limitations that it thought should be imposed, it mandated those emission limits, e.g., in Title II concerning motor vehicles.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 438 of 1275 this drafting approach is not unique to the CAA; on the contrary, as U.S. Supreme Court Associate Justice Kennedy has noted: Congress "usually does not legislate by specifying examples, but by identifying broad and general principles that must be applied to particular factual instances." 341 (3) Comments and responses. Some 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, 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

341 Pub. Citizen v. U.S. Dept. of Justice , 491 U.S. 440, 475 (1989) (Kennedy, J., concurring).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 439 of 1275 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 their terms limit 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, the affected sources subject to this rule are fully able to meet their emission standards by undertaking the measures described in building blocks 2 and 3. Moreover, as discussed, the measures in building blocks 2 and 3 are highly effective in achieving CO 2 emission reductions from these affected EGUs, given the unique characteristics of the industry. This reinforces the conclusion that the term “system of emission reduction” is broad enough to include these measures. 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 the affected sources. An example includes the requirement under CAA section 407(b)(2) that the EPA base the NO x emission limits for certain types of boilers “on the degree of reduction achievable through

the retrofit application of the best system of continuous*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 440 of 1275 emission reduction” and further requires the EPA to revise previously promulgated emission limits for certain types of boilers “to be more stringent if the [EPA] determines that more effective low NO x burner technolog y is available.” (Emphasis added.) These narrower specifications for the basis of these

Title IV emissions limits -- which were added in the 1990 CAA Amendments, at the same time that Congress revised the provisions of CAA section 111(a)(1) establishing the basis for controls under CAA section 111(d)(1) -- make clear that Congress

knew how to constrain the basis for emission limits to measures that are integrated into the design or operation of the affected source, and that its choice to base CAA section 111(d)(1) and (a)(1) standards of performance on a “system of emission reduction” indicates Congress’ intent to authorize a broader

basis for those standards. 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. These comments are 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 441 of 1275 done so expressly, as it did for the above-discussed Title IV NOx requirements. Third, the interpretations that commenters offer for these various provisions are not persuasive. 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), which is stationary sources, as opposed to other types of sources (such as mobile sources), the emissions from which are addressed under other CAA provisions (such as CAA Title II). 342

342 This purpose is made apparent by the terms of CAA section 111(a)(3), which contains two sentences. The first sentence provides, “The term ‘stationary source’ mans any building, structure, facility, or installation which emits or may emit any air pollutant.” The second sentence provides: Nothing in subchapter II of this chapter relating to nonroad engines shall*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 442 of 1275 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. In addition, 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 are able to take should be considered in determining the appropriate standards for the source’s emissions. Other provisions in CAA section 111 make clear the role of the owner/operator. CAA section 111(e) provides that for new sources, the burden of compliance falls on the “owner or operator.” 343 The same is necessarily true for existing sources. This supports the EPA’s view that the basis for whether a

be construed to apply to stationary internal combustion engines.” This second sentence makes clear that stationary internal combustion engines are to be regulated under section 111, and not Title II (relating to mobile sources), which confirms that the purpose of the definition of stationary source is jurisdictional in nature -- to identify the emissions that are to be regulated under section 111, as opposed to other CAA provisions. 343 CAA section 111(e) provides: (“[I]t shall be unlawful for any owner or operator of any new source to operate such source in violation of any [applicable] standard of performance.”)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 443 of 1275 control measure qualifies as a “system of emission reduction” under CAA section 111(d)(1) and (a)(1) is whether it is something that the owner/operator can implement in order to achieve the emissions standard assigned to the source – if so, the control measure should qualify as a “system of emission reduction” – and not whether the control measure is integrated into the source’s own design or operation. 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 emissions standard, which entails a numerical limit on emissions, is not appropriate because emissions cannot be measured, due either to the nature of the pollutant (i.e., the pollutant is not emitted through a conveyance) or the nature of the source category (i.e., the source category is not able to conduct measurements). CAA section 111(h) provides that a design standard is appropriate under those circumstances, but only under those

circumstances. When an emissions standard is appropriate,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 444 of 1275 including in the present rule, CAA section 111(h) is silent on which system of emissions reduction – whether limited to a source’s own design or operations -- may form the basis of the emissions standard. In any event, CAA section 111(h) applies only to standards promulgated by the Administrator, and therefore appears by its terms to be limited to CAA section 111(b) rulemakings for new, modified, or reconstructed sources, not CAA section 111(d) rulemakings for existing sources. 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 renewable energy, as indicated by Congress’s inclusion of those measures in Title IV (relating to acid rain), so that 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 445 of 1275 mark. The provisions of CAA section 111(d)(1) and (a)(1) do not explicitly include any specific control measures – neither renewable energy measures (like the ones Congress expressly included in Title IV), nor measures that are integrated into the sources’ design or operations (like the NO x control measures Congress also included in Title IV). But this contrast with other CAA provisions does not mean that Congress did not intend the BSER to include any of those types of measures. Rather, this contrast supports viewing CAA section 111(d)(1) and (a)(1) as a big toolbox that affords the EPA a broad range of measures to choose from in determining the BSER. 344

c. Chevron step 2 deference to interpret BSER to include the building blocks. Under the familiar Chevron step 2 analysis, if the plain meaning of the BSER provision under CAA section (a)(1) (and as applied under CAA section 111(d)(1)) does not answer the question of whether the phrase “system of emission reduction” includes the measures in building blocks 2 and 3, then the EPA’s interpretation that the provision does include those building blocks must be given deference as long as it is a reasonable

344 It should also be noted that Title IV is limited to one type of source – fossil fuel-fired EGUs – and as a result, lends itself to greater specificity about the types of control measures. Section 111(d), in contrast, applies to a wide range of source types, which, as discussed above, supports reading it to authorize a broad range of control measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 446 of 1275 construction of the statute. In its 2014 decision upholding CSAPR, the U.S. Supreme Court re-affirmed Chevron deference for carrying out the provisions of the CAA, noting: “We routinely accord dispositive effect to an agency’s reasonable interpretation of ambiguous statutory language.” 345 Moreover, in its 2011 decision holding that the CAA displaces the federal common law claim of nuisance, the U.S. Supreme Court generally recognized the breadth of CAA section 111, noting that “Congress delegated to the EPA the decision whether and how to regulate carbon-dioxide emissions from power plants....” 346 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) Consistency of building blocks 2 and 3 with the structure of the utility power sector. (a) Integration of the utility power system. Certain characteristics of the utility power sector are of central importance for why the measures of building blocks 2 and 3 qualify as part of the system of emission reduction. As discussed in detail above, electricity is fungible and the

345 EPA v. EME Homer City, 134 S. Ct. 1584, 1603 (2014). 346 American Electric Power v. Connecticut , 131 S. Ct. 2527, 2538 (2011) (“ AEP ”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 447 of 1275 utility power sector is highly integrated, so much so that it has been likened to a big machine. Specifically, the utility power sector is characterized by a physical interconnection between electricity generators themselves, and between those generators and electricity users. Because of the physical properties of electricity and the unavailability of large scale electricity storage, generation and load (or use) must be instantaneously balanced in real time. As a result, the utility power sector is uniquely characterized by extensive planning and highly coordinated operation. These features have been present for decades, and in fact, over time, the sector has become more highly integrated. Another important characteristics of the utility power sector is that although the states have developed both regulated and de-regulated markets, the generation of electricity reflects a least-cost dispatch approach, under which electricity is generated first by the generators with the lowest

variable cost.

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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 448 of 1275 institutional actors, to safeguard reliability and to assure

least cost service. Congress, 347 the Courts, 348 the EPA in its regulatory actions, 349 and states in their regulatory actions 350 have recognized the integrated nature of the utility power sector. (b) Significance of integrated utility sector for BSER. 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 leads to the instantaneous increase in generation from other generators. This allows for locational flexibility across

347 See CAA section 404(f)(2)(B)(iii)(I) (conditioning a utility’s eligibility for certain allowances on implementing an energy conservation and electric power plan that evaluates a range of resources to meet expected future demand at least cost); see also Sen. Rep. No. 101-228, pp. 319-20 (Dec. 20,1989)(recognizing that “utilities already engage in powerpooling arrangements to ensure maximum flexibility and efficiency in supplying power” to support the establishment of an allowance system under title IV). 348 New York v. Federal Energy Regulatory Commission , 535 U.S. 1, at 7 (2002) (citing Brief for Respondent FERC 4-5). 349 “Stack Heights Emissions Balancing Policy,” 53 Fed. Reg. 480, 482 (Jan. 7, 1988). 350 See 79 FR 34830, 34880 (June 18, 2014) (discussing State of California Global Warming Solutions Act of 2006, Assembly Bill 32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001- 0050/ab_32_bill_20060927_chaptered.pdf, and quoting December 27, 2013 Letter from Mary D. Nichols, Chairman of California Air Resources Board, to EPA Administrator Gina McCarthy).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 449 of 1275 the sector in meeting demand for electricity services. The institutions that coordinate planning and operations routinely use this flexibility to economically meet demand for electricity services 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 orcause the generation of increased amounts of lower- or zeroemitting electricity – through contractual arrangements, investment, or purchase -- which will back out higher-emitting generation, and thereby lower emissions. In addition, fossil*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 450 of 1275 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 be noted that CO 2 is particularly well-suited for building blocks 2 and 3 because it is a global, not local, air pollutant, so that the location where it is emitted does not affect its environmental impact. The U.S. Supreme Court in the

UARG case highlighted the importance of taking account of the unique characteristics of CO 2 . 351 (2) Current implementation of measures in building blocks 2 and 3. 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 2 emissions. 352 This is a strong indicator that these

351 See UARG v. EPA, 134 S. Ct. 2427, 2441 (2014). 352 A number of utilities have climate mitigation plans. Examples include National Grid,http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as px; PG&E, http://www.pge.com/about/environment/pge/climate/; and Austin Energy,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 451 of 1275 measures should be considered part of a “system of emission

reduction” for CO 2 emissions from these sources. The requirement that the “system of emission reduction” be “adequately demonstrated” indicates that the implementation of control mechanisms or other actions that the sources are already taking to reduce their emissions are of particular relevance in establishing the emission reduction requirements of CAA section 111(d)(1) and (a)(1). As a result, such measures are a logical starting point for consideration as a “system of emission

reduction” under CAA section 111. (3) Reliance in CAA Title IV on building block measures. Some of the building block 2 and 3 approaches to reducing emissions in the utility power sector were also well recognized at the time that Congress adopted the 1970 CAA Amendments. 353 Over time, these techniques have become more established within the industry, and by the 1990 CAA Amendments, Congress expresslybased the Title IV acid rain controls for existing fossil fuelfired EGUs on the same measures that are in those building

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 353 See, e.g. , Shepard, Donald S., A Load Shifting Model for Air Pollution Control in the Electric Power Industry , Journal of the Air Pollution Control Association, Vol. 20:11, pp. 756-761 (November 1970).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 452 of 1275 blocks. This provides an important indication that Congress not only viewed such measures as effective emission control techniques but that these same measures were already in use by the industry. (a) Overview. 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 sulfur dioxide emissions. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 453 of 1275 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), i.e., eliminating the percentage reduction and most of the other limitations under the 1977 CAA Amendments, on the continued applicability of the Title

IV SO 2 cap, so that if the cap were eliminated, the changes would, by operation of law, also be eliminated, and the 1977 version of section 111(a)(1) would be reinstated. 354 Additionally, Congress authorized the EPA to establish standards of performance for new and existing industrial (non-EGU) sources

of SO 2 emissions if emissions from these sources might exceed 1985 levels and failed to decline at the expected rate. 355 While

354 1990 CAA Amendments, § 403, 104 Stat. at 2631 (requiring new units to hold allowances for each ton of sulfur dioxide emitted). Congress believed that mandating a technological standard through the percentage reduction requirement in Section 111(a)(1) would ensure the continued availability of low sulfur coal for existing sources. In other words, the percentage reduction requirement discouraged compliance with new source performance standards based solely on fuel shifting because it was much more costly to achieve the percentage reduction with lower sulfur coal. This belief was expressed during the 1977 CAA Amendments and is discussed above as part of the legislative history of Section 111. 355 1990 CAA Amendments, § 406, 104 Stat. at 2632-33; see also Sen. Rep. No. 101-228, at 282 (industrial source emissions totaled 5.6 million tons of SO 2 in 1985).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 454 of 1275 industrial sources were not required to participate under Title IV — they could elect to do so, under CAA section 410(a) — Congress believed SO 2 reductions from these sources were “an essential component of the reductions sought under [Title IV]” and intended that Title IV would “assure[] that these projected reductions occur and will not be overcome by future growth in

emissions.” 356 As such, Congress viewed federal standards of performance as the appropriate backstop to Title IV even for sources that could not otherwise be regulated under CAA section 111(d). 357 Together, these signals suggest that it is reasonable for the EPA to consider Title IV when interpreting and implementing CAA section 111. For present purposes, the essential features of Title IV are that it regulates sulfur dioxide emissions from coal-fired EGUs by adopting a nationwide cap of 8.90 million tons to be achieved through a tradable allowance system. As we explain below, the provisions of Title IV and its legislative history make clear that Congress based the stringency of the emission limitation requirement (8.90 million tons) and the overall structure of the approach (a cap-and-trade system) on Congress’s

356 Sen. Rep. No. 101-228, at 345 (Dec. 20, 1989). 357 To reiterate, ordinarily, standards of performance cannot be used to regulate SO 2 emissions from existing sources because of the pollutant exclusions in CAA section 111(d).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 455 of 1275 recognition that the affected EGUs had a set of tools available to them to reduce their emissions, including through a shift to lower emitting generation and use of renewable energy, along with add-on controls and other measures. Thus, Title IV provides a close analogy to CAA section 111: generation shift and renewable energy were part of Congress’s basis for the Title IV emissions requirements, and that is analogous to building blocks 2 and 3 serving as part of the “system of emission reduction” that is the EPA’s basis for the section 111(d) emission guidelines. For this reason, the fact that in Title IV, Congress relied on generation shift and renewable energy as the basis for

the SO 2 emission limitations for affected EGUs strongly supports interpreting CAA section 111(d)(1) and (a)(1) to include use of those same measures as part of the “system of emission

reduction” as the basis for CO 2 emission limitations for those

same sources. (b) Title IV provisions. 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 following: §401(a). Findings The Congress finds that –

* * * **** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 456 of 1275 (4) 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. (Emphasis added.) Title IV then includes the following statement of its “purposes:” §401(b). Purposes The purpose of this subchapter [Title IV] is to reduce the adverse effects of acid deposition through reductions in annual emissions of sulfur dioxide ... and nitrogen oxides.... It is the intent of this subchapter to effectuate such reductions by requiring compliance by affected EGUs with prescribed emission limitations by specified deadlines which limitations may be met through alternative methods of compliance provided by an emission allocation and transfer system. It is also the purpose of this subchapter 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. (Emphasis added). By its terms, this statement of Title IV’s purposes explicitly embraces the use of renewable energy. Moreover, the legislative history makes clear that the reference in the “findings” section quoted above to “strategies and technologies” includes generation shift to lower-emitting generation. Specifically, the Senate Report stated that an “allowance system” 358 would encourage such “technologies and strategies” as –

358 See Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 457 of 1275 energy efficiency; enhanced emissions reduction or control technologies—like sorbent injection, cofiring with natural gas, integrated gasification combined cycles; fuel-switching and least-emissions dispatching in order to maximize emissions reductions.” 359 Congress’s reliance on generation shifting and renewable energy to reduce acid rain precursors from affected EGUs in Title IV strongly supports the EPA’s authority to identify those same measures as part of the CAA section 111 “system of emission

reduction” to reduce CO 2 emissions from those same sources. In addition, Title IV includes other provisions expressly concerning renewable energy. In CAA section 404(f) and (g), Congress set aside a special pool of allowances to encourage use of renewable energy. In order to obtain a special allowance, an electric utility needed to pay for qualifying renewable energy sources “directly or through purchase from another person.” These measures confirm Congress’s recognition that renewable energy was available to the industry, was desirable to encourage from a policy perspective, and was appropriate to consider in determining the amount of pollution reduction the law should require. (c) Title IV legislative history. Numerous statements in the legislative history confirm that Congress based the Title IV

359 See Sen. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis added).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 458 of 1275 requirements on the fact that affected EGUs could reduce their

SO 2 emissions through a set of measures, including shifting to lower-emitting generation as well as reliance on renewable

energy. For example, the Senate Committee Report 360 and Senator Baucus, 361 a member of the Senate Committee on Environment and

Public Works and Chairman of the House and Senate Clean Air Conferees, both emphasized that affected EGUs could rely on, among other things, “least-emissions dispatching in order to maximize emissions reductions.” Similarly, statements supporting the renewable energy reserve were included in the legislative history on the House side. 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. 362

360 Sen. Rep. to accompany S. 1630, Sen. Rep. 101-228 (Dec. 20, 1989), 1990 CAA Legis. Hist. at 8656 361 Sen. Debates on Conf. Rep. to accompany S. 1630, H. Rep. 101- 952 (Oct. 27, 1990), 1990 CAA Legis. Hist. at 1033-35 (statement of Senator Baucus, inserting “the Clean Air Conference Report” into the record). 362 H.R. Rep. No. 101-490, pp. 368-69; 674-76 (May 17, 1990) (additional views of of Reps. Markey and Moorhead) (“We believe that H.R. 3030, as amended, will create a strong and effective incentive for utilities to immediately pursue energy conservation and renewable energy sources as key components of their acid rain control strategies.”); see also Rep. Collins, H. Debates on H.R. Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA Legis. Hist. at 1307 (“The bottom line is that our Nation's*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 459 of 1275 Congress’s reliance, in adopting Title IV, on generation shifting and renewable energy as part of the basis for the

emission standards contrasts with circumstances in which emissions standards were established based on add-on controls,

but other measures – such as renewables – were seen as a compliance alternative. Examples of the latter are two of the air pollutant transport rules that the EPA promulgated after the

1990 CAA Amendments: the NO x SIP Call (1998) and the Clean Air Interstate Rule (CAIR) (2005). For each of those rules, the EPA established the emission standards and requirements in large part on the basis of add-on controls, but authorized and encouraged the implementation of renewable energy measures as compliance measures. 363 (4) Reliance on renewable energy measures to reduce carbon dioxide. The Title IV legislative history also makes clear that Congress viewed renewable energy measures as a means to reduce

utilities and production facilities must reach beyond coal, oil, and fossil fuels. The focus must shift instead toward conservation and renewables such as hydropower, solar thermal, photovoltaics, geothermal, and wind. These clean sources and energy, available in virtually limitless supply, are the way of the future.”). 363 CAIR: 70 Fed. Reg. 25,162, 25, 165, 25,256, 25, 279 (May 12, 2005) (allowing use of allowance set-asides for renewables and energy efficiency); NO x SIP Call: 63 Fed. Reg. 57,356, 57,362, 57438 (Oct. 27, 1998) (authorizing SIPs to rely on renewables and energy efficiency to meet the state budgets).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 460 of 1275 carbon dioxide for the purpose of mitigating climate change. By the time of the 1990 CAA Amendments, Congress had long been aware that emissions of carbon dioxide and other greenhouse gases put upward pressure on world temperatures and threatened to change the climate in destructive ways. In 1967, President Lyndon Johnson sent a letter to Congress recognizing that carbon dioxide was changing the composition of the atmosphere. 364 The record for the 1970 CAA Amendments include hearings 365 and a report by the National Academy of Sciences noting that carbon dioxide emissions could heat the atmosphere. 366 A 1976 report noted the phenomenon was included in the record for the 1977 CAA

364 “Special Message to the Congress on Conservation and Restoration of Natural Beauty (Feb. 8, 1965). http://www.presidency.ucsb.edu/ws/?pid=27285 (“This generation has altered the composition of the atmosphere on a global scale through radioactive materials and a steady increase in carbon dioxide from the burning of fossil fuels.”). 365 Administration Testimony, House Hearing (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381 (testimony of Charles Johnson, Jr., Administrator of the Consumer Protection and Environmental Health Service, stating that “the carbon dioxide balance might result in the heating up of the atmosphere whereas the reduction of the radiant energy through particulate matter released to the atmosphere might cause reduction in radiation that reaches the earth”). 366 1970 CAA Legis. Hist. at 244, 257 Sen. Debate on S. 4358 (Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter IV of the Council on Environmental Quality’s first annual report, which states, “the addition of particulates and carbon dioxide in the atmosphere could have dramatic and long-term effects on world climate.”)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 461 of 1275

Amendments. 367 A 1977 Report by the National Academy of Sciences warned that average temperatures would rise due to the burning

of fossil fuel. 368 By the time of the 1990 CAA Amendments, the dangers had become more clearly evident. Senate hearings beginning in 1988 had presented testimony from Dr. James E. Hansen of the National Aeronautics and Space Administration and other scientists that described the dangers of climate change caused by anthropogenic carbon dioxide and other greenhouse gas emissions and asserted that as a result of those emissions, the climate was in fact already changing. 369

367 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) (statement of Sen. Bumpers) (inserting into the record, “Summary of Statements Received from Professional Societies for the Hearings on Effects of Chronic Pollution (in the Subcommittee on the Environment and the Atmosphere),” which stated, “there is near unanimity that carbon dioxide concentrations in the atmosphere are increasing rapidly. Though even the direction (warming or cooling) of the climate change to be caused by this is unknown, very profound changes in the balance of climate factors that determine temperature and rainfall on the earth are almost certain within 100 years”). 368 National Academy of Sciences, “Energy and Climate: Studies in Geophysics” viii (1977). http://www.nap.edu/openbook.php?record_id=12024 (noting that a fourfold to eightfold increase in carbon dioxide by the latter part of the twenty-second century would increase average world temperature by more than 6 degrees Celsius). 369 Sen. Rep. No. 101-228, p. 322 (Dec. 20, 1989), at 1990 Leg. Hist. at 8662 ( **“** 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.”); History, Jurisdiction, and a Summary of Activities of the Committee on Energy and Natural Resources During the 100 th*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 462 of 1275 In enacting the 1990 CAA Amendments, Congress identifiedreductions in carbon dioxide emissions as an important cobenefit of the reductions in coal use and stressed that the renewable energy measures would achieve those reductions. Senator Fowler, the author of the provision that established a renewable energy technology reserve within the allowance system, noted that renewable energy technologies, “can greatly reduce emissions of ... global warming gases. That makes them a potent weapon against catastrophic climate change....” 370 In addition, the 1990 CAA Amendments required EGUs covered by the monitoring requirements of the Title IV acid rain program to report their

CO 2 emissions. (5) Other EPA actions that rely on the building block measures. Another indication that it is reasonable to interpret the CAA section 111(d)(1) and (a)(1) provisions for 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.

Congress, Sen. Rep. No. 101-138, 5 (Sept. 1989); “Global Warming Has Begun, Expert Tells Senate,” New York Times, June 24, 1988http://www.nytimes.com/1988/06/24/us/global-warming-has-begunexpert-tells-senate.html. 370 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 7106.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 463 of 1275 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). 371 The EPA established a nationwide cap-and-trade program that took effect in two phases: In 2010, the cap was set at 38 tons per year, and in 2018, the cap was lowered to 15 tons per year. The EPA expected, on the basis of modeling, that sources would achieve the second phase, 15-ton per year cap cost-effectively by choosing among a set of measures that included shifting generation to lower-emitting units. 372 CAMR was vacated by the D.C. Circuit on other grounds, 373 but it provides a precedent for relying on shifting generation as part of the BSER in a CAA section 111(d) rulemaking for fossil fuel-fired EGUs. In 2011, the EPA promulgated the Cross State Air Pollution Rule (CSAPR), 374 in which it set statewide emission budgets for

371 70 FR 28606 (May 18, 2005) (“Under the CAMR scenario modeled by EPA, units [were] projected to meet their SO 2 and NO x requirements and take additional steps to address the remaining [mercury] reduction requirements under CAA section 111, including adding [mercury]-specific control technologies (model applies [activated carbon injection]), additional scrubbers and [selective catalytic reduction], dispatch changes , and coal switching.”). 372 70 FR 28606, 28619 (May 18, 2005). 373 New Jersey v. EPA , 517 F.3d 574, 583-84 (D.C. Cir. 2008), cert. denied sub nom

. Util. Air Reg. Grp. v. New Jersey , 555 U.S. 1169 (2009) 374 76 Fed. Reg. 48208 (Aug. 8, 2011).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 464 of 1275

NO x , SO 2 , and particulate matter emitted by fossil fuel-fired EGUs, and based those standards in part on shifts to lower emitting generation. CSAPR established state-wide emissions budgets based on a range of cost-effective actions that EGUs could take, and set the stringency of the deadlines for some required reductions in part because of the availability of “increased dispatch of lower-emitting generation which can be achieved by 2012.” 375 The EPA developed a federal implementationplan (FIP) that established a trading program to meet the statewide emission budgets set by CSAPR. The EPA projected that sources would meet their emission reduction obligations by implementing a range of emission control approaches, including the operation of add-on controls, switches to lower-emitting coal, and “changes in dispatch and generation shifting from

375 76 Fed. Reg. at 48452.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 465 of 1275 higher emitting units to lower emitting units.” 376 The U.S. Supreme Court upheld CSAPR in EME Homer v. EPA

. 377 With respect to renewable energy, in 2004, the EPA provided guidance to states for adopting attainment SIPs under CAA section 110 that include renewable energy measures. 378 Some states have done so. For example, Connecticut included in its SIP reductions from solar photovoltaic installations. 379 In 2012,

376 76 FR at 48279-80. The exact mix of controls varied for different air pollutants and different time periods, but in all cases, shifting generation from higher to lower emitting unitswas one of the expected control strategies for the fossil fuelfired power plants. Prior to CSAPR, the EPA promulgated two other transport rules, the NO x SIP Call (1998) and the Clean Air Interstat1e Rule (CAIR) (2005). For both of those rules, the EPA established the emission standards on the basis of add-on controls and the availability of trading, but authorized andencouraged the implementation of renewable energy and demandside energy efficiency measures. CAIR: 70 Fed. Reg. 25162, 25165, 25256, 25279 (May 12, 2005) (allowing use of allowance set-asides for renewables and energy efficiency); NO x SIP Call: 63 Fed. Reg. 57356, 57362, 57436, 57438, 57449 (Oct. 27, 1998) (authorizing and encouraging SIPs to rely on renewables and energy efficiency to meet the state budgets). 377 134 S. Ct. 1584 (2014). 378 See, e.g., Guidance on SIP Credits for Emission Reductions from Electric-Sector Energy Efficiency and Renewable Energy Measures (Aug. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem

_ gd.pdf; Incorporating Emerging and Voluntary Measures in a State Implementation Plan (SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/evm

_ ievm

_ g.pdf

. 379 CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1 619 (see Attainment Demonstration TSD, Chapter 8 at 31, http://www.ct.gov/deep/lib/deep/air/ regulations/proposed

_ and

_ reports/section

_ 8.pdf ).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 466 of 1275 the EPA provided additional guidance on this topic. 380 In addition, the EPA has partnered with the Northeast states for Coordinated Air Use Management (NESCAUM) and three states (Maryland, Massachusetts, and New York) to identify opportunities for including renewable energy in a SIP and to provide real-world examples and lessons learned through those

states’ case studies. 381 (6) Other rules that relied on actions by other entities. 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 emissions trading or

380 “Roadmap for Incorporating EE/RE Policies and Programs into SIPs/TIPs” (July 2012), http://epa.gov/airquality/eere/manual.html. 381 States’ Perspectives on EPA’s Roadmap to Incorporate Energy Efficiency/Renewable Energy in NAAQS State Implementation Plans: Three Case Studies, Final Report to the U.S. Environmental Protection Agency (Dec. 2013),http://www.nescaum.org/documents/nescaum-final-repttoepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf

.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 467 of 1275 averaging, in which many sources meet their emission limitation requirements by purchasing allowances or emission reduction

credits from other sources that reduce emissions. (a) Third party transactions. 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 468 of 1275 install the controls needed by the affected EGUs. 382 In addition, EGU owners and operators may be dependent on the actions of third-parties to finance the controls and third-party regulators to assure the mechanism for repaying that financing. However, this dependence does not mean that the emission limit based on that equipment is not achievable. Rather, the fact that the owner or operator of the affected source can engage in a market transaction with the various third parties to acquire, install, and pay for the equipment means that emission limit is

achievable. 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

382 70 Fed. Reg. 25162, 25216–25225 (May 12, 2005). The EPA noted that its view was “based on the NO X SIP Call experience.” Id. at 25217.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 469 of 1275 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) Emissions trading and averaging. 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 allowances or emission reduction 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 emission reduction 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 on their own design or operations, but rather by purchasing allowances or emission reduction credits. These*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 470 of 1275 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 emission reduction credits. Trading programs have been commonplace under the CAA, particularly for EGUs, for decades. The rest of this subsection briefly describes some of the main trading programs, focusing on the ones that primarily involve EGUs. For the reasons just described, these trading rules refute commenters’ arguments for limiting the scope of the “system of emission reduction.” In the 1990 CAA Amendments, Congress enacted the Acid Rain Program, as Title IV of the CAA. The Acid Rain Program applied to new and existing electric generating units in two phases. Phase II, which started in the year 2000, applies to more than 2000 fossil fuel-fired EGUs across the continental U.S., and imposes an annual cap on SO 2 emissions of 8.90 million tons, which was designed to achieve overall reductions of ten million

tons of SO 2 emissions or approximately a 50 percent reduction from 1980 emission levels. Under the program each affected EGU

must surrender one allowance for each ton of SO 2 that it emits.

Each affected EGU is allocated a number of allowances for free. An affected EGU that implements controls may reduce its emissions to the point where it may have more allowances than*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 471 of 1275 tons of emissions, in which case it can sell the allowances it

does not need for its own emissions. An affected EGU that does not implement controls may not have enough allowances for its emissions and may therefore need to buy some. In enacting the program, Congress explicitly recognized that some sources would comply by purchasing allowances instead of implementing controls. Indeed, the purpose of the program was to achieve emission reductions by focusing controls on the sources for which controls were most cost-effective, and allow other sources to avoid implementing controls directly, and instead to purchase allowances, which had the effect of defraying part of the costs of controls for the sources that did implement controls. 383 Prior to the development of the concept of trading, legislative efforts to reduce SO 2 from fossil fuel-fired EGUs had failed because the cost of implementing controls were considered too expensive for some of the EGUs. Trading solved that problem. In addition, in enacting the trading program, Congress recognized that the power sector was particularly well-suited to

383 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 472 of 1275 implement a trading program because of the highly transactional nature of the industry. 384 The EPA has promulgated a series of rulemakings that apply to EGUs and that are based on the acid rain program. The EPA has promulgated several of these rules under CAA section 110(a)(2)(D)(i)(I), the “good neighbor provision,” which requires an upwind state to include in its SIP measures to reduce emissions from its sources that adversely affect air quality in a downwind state. In 1998, the EPA promulgated the first of these transport rules, originally called the NO x SIP Call, and currently called the NO x Budget Trading Program. This

rule set NO x emission budgets for certain states, and based each state’s budget on the cumulative emissions reductions that could be achieved primarily by the fossil fuel-fired EGUs in that state by implementing “highly cost-effective controls.” For

384 See Sen. Rep. No. 101-228, pp. 319-20 (Dec. 20, 1989) (“In the management of the power they produce and deliver, utilities already engage in power-pooling arrangements to ensure maximum flexibility and efficiency in supplying power. Allowance-pooling could easily track power-pooling activities. At the same time, utilities have substantial experience in making long-term power and capacity sales to other utilities and could to [sic] the same with allowances, enabling those with up-front capital costs to receive revenues at the time they are incurring their expenses. In fact, a utility seeking to obtain allowances in lieu of making on-site reductions in order to meet compliance could underwrite directly a portion of the control technology or other costs incurred by the utility from whom it was to obtain the additional allowances.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 473 of 1275 EGUs, the emission rate was 0.15 lb/MMBtu for both oil/gas-fired EGUs and coal-fired EGUs. The EPA concluded that while it might

be less cost-effective for some individual EGUs to meet that emission rate through installing on-site controls, those EGUs could purchase allowances through a trading program, so that overall the emission rate remained highly cost-effective. 385 The EPA explained -- In this rulemaking, EPA has chosen to focus on an average cost-effectiveness measure in identifying highly cost-effective control options for several reasons. Since EPA's determination for the core group of sources is based on the adoption of a broad-based trading program , average cost-effectiveness serves as an adequate measure across sources because sources with high marginal costs will be able to take advantage of this program to lower their costs. 386 In 2005, the EPA promulgated an expanded and more stringent transport rule, the CAIR, which regulated SO 2 as well as NO x emissions from fossil fuel-fired EGUs through a tradable allowance system. Similar to the NO x SIP Call, the state budgets set by CAIR were based on cost-effective controls on EGUs. The EPA’s evaluation of the cost impacts of CAIR assumed that EGUs would be participating in an interstate trading program. 387 The EPA explained that -- In modeling the CAIR with the IPM, EPA assumes interstate emissions trading. While EPA is not

385 63 Fed. Reg. 57356, 57399, 57413, 57457 (Oct. 27, 1998). 386 63 FR at 57399 (emphasis added). 387 70 Fed. Reg. 25162, 25196 (May 12, 2005).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 474 of 1275 requiring states to participate in an interstate trading program for EGUs, we believe it is reasonable to evaluate control costs assuming states choose to participate in such a program since that will result in less expensive reductions. 388 In 2011, the EPA promulgated the CSAPR, which regulated interstate transport of SO 2 , NO x , and particulate matter emissions from fossil fuel-fired EGUs through a tradable allowance system. 389 Here, again, the EPA concluded that -- the preferred trading remedy will allow source owners to choose among several compliance options to achieve required emission reductions in the most cost effective manner, such as installing controls, changing fuels, reducing utilization, buying allowances , or any combination of these actions. 390 As with the previous two interstate transport programs, the EPA in CSAPR recognized that interstate trading was a particularly well-suited mechanism for addressing emissions from EGUs because of “the power sector’s ability to operate as an integrated, interstate system and to promote reliability.” 391 In fact, the Acid Rain Program and the transport rules have resulted in large numbers of fossil fuel-fired EGUs purchasing allowances instead of implementing controls. For example, SO 2 control options available to sources include switching to low

388 70 Fed. Reg. at 25196. 389 76 Fed. Reg. 48208 (Aug. 8, 2011). 390 76 Fed. Reg. at 48272.

391 76 Fed. Reg. at 48272.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 475 of 1275 sulfur coal, employing various types of flue gas desulfurization (FGDs), or utilizing fluidized bed limestone units, as well as purchasing allowances. As Table 5, below, shows, as of 2012,

more than half the coal-fired EGUs in the ARP and CAIR annual SO 2 program, which EGUs generate 33 percent of the electricity from coal-fired units in those programs, comply with their ARP and

CAIR SO 2 emission limits simply by holding allowances – many of which are purchased from other entities – and without implementing controls.

**Table 5. SO 2**  **Controls in 2012 on Coal-Fired Units in the ARP and CAIR Annual SO**  **2 Program**  392

SOx Control Type Number of

Units Share of Units Share of MWh

Generation

FGD 468 44% 66%

Other 43 49% 1%

Uncontrolled 545 52% 33% Source: EPA, 2013 By the same token, in 2005, the EPA promulgated rulemaking under CAA section 111(d) to control mercury emissions from affected EGUs: The CAMR. The rule promulgated a two-phase, nationwide, interstate, allowance-based cap-and-trade program for mercury. The EPA specified budgets for each state, based on

392 http://epa.gov/airmarkets/progress/ARPCAIR12.html*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 476 of 1275 the sum of allowances allocated to each existing EGU located in the state. The number of allowances allocated to a particular EGU were based on the EGU’s pro rata share of the overall national cap on mercury emissions. In the first phase, the cap was 38 tons per year, and in the second phase, the cap was reduced to 15 tons per year. The EPA recognized that in the second phase, not all sources could cost-effectively install pollution control technology, but that the trading program would allow some sources to meet their requirements by “buying

allowances.” 393 The EPA’s regional haze rules provide another example of a trading program in which sources – primarily, fossil fuel-fired EGUs – choose to meet their emission limits by purchasing allowances from other sources in lieu of implementing controls. CAA section 169A required the EPA to promulgate regulations to assure reasonable progress toward meeting the national visibility goal. CAA section 169A(b)(2) required the EPA to include in its regulations a requirement that states revise their SIPs to include “emission limitations, schedules of compliance and other measures as may be necessary to make reasonable progress toward the national goal,” including a requirement that certain older stationary sources “procure,

393 70 Fed. Reg. 28606, 28619 (May 18, 2005).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 477 of 1275 install, and operate ... the best available retrofit technology,” more commonly known as BART. A 1993 Ninth Circuit decision held that the EPA could decide “not to adopt the emission control limits indicated by BART analysis, but instead to adopt an emission limitations standard that would produce greater visibility improvement at a lower cost.” 394 In 1999, the EPA promulgated the Regional Haze Rule, which allowed states to adopt trading programs or other alternatives in lieu of requiring retrofit controls at sources subject to

BART. 395 Specifically, the Regional Haze Rule provides: A state may opt to implement or require participation in an emissions trading program or other alternative measure rather than to require sources subject to BART to install, operate, and maintain BART. 396 In a challenge to revisions to the Regional Haze Rule in 2003, the D.C. Circuit held that the EPA had reasonably interpreted section 169A(b)(2) as permitting alternatives to BART, including trading programs, so long as they achieve greater reasonable progress than would the installation of retrofit controls. 397 The

394 Central Arizona Water District v. EPA , 990 F.2d 1531, 1543 (9 th Cir. 1993). 395 64 FR 35,714 (July 1, 1999) (codified at 40 C.F.R. 51.308- 309). 396 40 CFR 51.308(e)(2). 397 Ctr. for Econ. Dev. v. EPA , 398 F.3d 653, 660 (D.C. Cir. 2005).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 478 of 1275 EPA has since approved several regional haze trading programs in

lieu of BART. 398 (7) Consistency with the pollution prevention goals of the CAA. Interpreting the term “system of emission reduction” broadly to include the building blocks is also consistent with a primary purpose of the CAA, which is 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.” CAA section 101(a)(3) describes “air pollution prevention” as “the reduction or elimination, through any measures, of the amount of pollutants produced or created at the source”. (Emphasis added.) The reference to “any measures” highlights the breadth of what Congress considered to be pollution prevention, that is, any and all measures that reduce or eliminate pollutants at the source. 399

398 See, e.g. , 77 FR 33,642 (June 7, 2012) (codified at 40 C.F.R. § 51.308(e)(4)) (authorizing eastern states to rely on CSAPR in lieu of BART). 399 Section 101 emphasizes the importance of air pollution prevention in two other provisions: CAA section 101(b)(4) states that one of “the purposes of [title I of the CAA, which includes*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 479 of 1275 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].” In light of one of 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. (8) Additional considerations. Interpreting CAA section 111(d)(1) and (a)(1) to include building blocks 2 and 3 is consistent with the spirit of the CAA, including Congress’s intention to address urgent and severe environmental problems; to be precautionary in protecting public health and welfare against risks; and to promote technological advancement, based on the expectation that American industry could be able to come up with innovative solutions to those environmental problems. The 1970 CAA Amendments were designed to address urgent and severe problems, and authorized stringent remedies that were necessary to address those problems. Congress viewed the air

section 111] are ... (b) to encourage and assist the development and operation of regional air pollution prevention and control programs.” CAA section 101(a)(3) adds: “The Congress finds -- ... (3) that air pollution prevention ... and air pollution control at its source is the primary responsibility of states and local governments.”*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 480 of 1275 pollution problem in 1970 as a crisis, 400 and enacted a stringent response, designed to match the severity of the problem. At the same time, Congress did not foreclose the EPA’s ability to address new environmental concerns; in fact, Congress largely deferred to the EPA’s expertise in identifying pollutants and sources that adversely affect public health or welfare. In doing so, Congress authorized the EPA to establish ambient air quality standards to protect public health with an ample margin of safety, and required states to develop plans to assure that their air quality areas would meet those standards by no later than five years. Congress also required the EPA to establish

400 1970 was a significant year in environmental legislation, but it was also marked as “a year of environmental concern.” Sen. Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 223. By mid-1970, Congress recognized that “[o]ver 200 million tons of contaminants [were] spilled into the air each year in America.... And each year these 200 million tons of pollutants endanger the health of [the American] people.” Id. at 224. “Cities up and down the east coast were living under clouds of smog and daily air pollution alerts.” Sen. Muskie, Sen. Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 124. Put simply, America faced an “environmental crisis.” Sen. Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 224. The conference agreement, it was reported, “faces the air pollution crisis with urgency and in candor. It makes hard choices, provides just remedies, requires stiff penalties.” Sen. Muskie, Sen. Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. “[I]t represents [Congress’] best efforts to act with the knowledge available ... in an affirmative but constructive manner.” Id. at 150.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 481 of 1275 standards for hazardous air pollutants that could result in shutting sources down. Congress added stringent controls on automobiles, overriding industry objections that the standards were not achievable. In addition, Congress added CAA section 111(b), which required the EPA to list categories based on harm to public health and regulate new sources in those categories. Congress then designed CAA section 111(d) to assure, as the Senate Committee Report for the 1970 CAA Amendments noted, that “there should be no gaps in control activities pertaining to stationary source emissions that pose any significant danger to public health or welfare.” 401 Addressing CO 2 emissions from the utility power sector as the EPA does in this rule is consistent with Congress’s recognition of the need to effectively address severe and urgent public health threats from air pollution. Moreover, this rule is consistent with the comprehensive approach of the CAA. Congress was clear that “the [CAA] is the comprehensive vehicle for

401 S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 (discussing section 114 of the Senate Committee bill, which was the basis for CAA section 111(d)). Note that in the 1977 CAA Amendments, the House Committee Report made a similar statement. House Comm. Rep. 95-294, at 41, Leg. Hist. vol. 4 at 2509 (discussing a provision in the House Committee bill that became CAA section 122, requiring EPA to study and then take action to regulate radioactive air pollutants and three other air pollutants).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 482 of 1275 protection of the Nation’s health from air pollution.” 402 The building blocks are the methods available for meaningfully addressing CO 2 emissions from existing affected EGUs on an industry-wide basis. This final rule is also consistent with the precautionary nature of the CAA. For example, the CAA authorizes the EPA to regulate air pollutants as soon as the EPA can determine that those pollutants pose a risk of harm, and not to wait until the EPA can prove that those pollutants actually cause harm. 403Similarly, as discussed next, the CAA generally is technologyforcing. The precautionary nature of the CAA extends to the present rule, in which the EPA regulates on the basis of building blocks 2 and 3, because the range of available and cost-effective measures in those building blocks achieves more pollution reduction than building block 1 alone. Indeed, add-on controls are not as cost-effective on an industry-wide basis, and while the costs of the add-on controls can be expected to be reduced over time, it is not consonant with the precautionary spirit of the CAA to wait.

402 House Comm. Rep. 95-294, at 41, Leg. Hist. vol. 4 at 2509 403 See 1977 House Comm. Rep. 95-294 at 49, 4 Leg. Hist. at 2516 (describing the CAA as being designed to have a “preventive or precautionary nature..., i.e., to assure that regulatory action can effectively prevent harm before it occurs; to emphasize the predominant value of protection of public health”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 483 of 1275 This final rule is also consistent with the purpose of CAA section 111 to advance technology. The legislative history and caselaw 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) 404 ; (ii) the expanded use of the best demonstrated technology; 405 and (iii) the development of emerging technology. 406 This rule is consistent with the second of those ways – it expands the use of the measures in building blocks 2 and 3, which are already established and provide the most reductions at the least cost. As discussed below, the use of the measures in these building blocks will be most fully expanded when organized markets develop, and our expectation that those markets will develop is consistent with the Congress’s view,

404 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduction must “look[] toward what may fairly be projected for the regulated future, rather than the state of the art at present”). 405 See 1970 Senate Committee Report No. 91-1196 at 15 (“The maximum use of available means of preventing and controlling air pollution is essential to the elimination of new pollution problems”). 406 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a standard of performance designed to promote the use of an emerging technology).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 484 of 1275 just described, that section CAA 111 promote technological

innovation. 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 andsevere problem of air pollution. This is manifest in the wellrecognized 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 earlier 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 could meet the challenges of developing air pollution controls as well. 407

407 Sen. Muskie, Sen. Debates on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 227 (“At the beginning of World War II industry told President Roosevelt that his goal of 100,000 planes each year could not be met. The goal was met, and the war was won. And in 1960, President Kennedy said that America would land a man on the moon by 1970. And American industry did what*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 485 of 1275 Commenters have stated that the proposed rule “would transform section 111 into something untethered to its statutory language and unrecognizable to the Congress that created it.” 408 On the contrary, we believe that this rule would be instantly recognizable to the Congresses that created and amended CAA section 111. This final rule would be recognizable to the Congress that adopted CAA section 111 in 1970 as part of a stringent, comprehensive, law to address the air pollution crisis, that challenged industry to meet that crisis with the same creative energy that won World War II, and that gave the EPA broad authority – under section 111 and other provisions –

to craft the needed emission limitations. This final rule would be recognizable to the Congress that revised CAA section 111 in 1977 to explicitly authorize that standards be based on actions taken by third parties (fuel cleaners). And this final rule would be recognizable to the Congress that revised CAA section 111 in 1990 to be linked to the Acid Rain Program that Congress adopted at the same time, which regulated the same industry (fossil fuel-fired EGUs) through some of the same measures

had to be done. Our responsibility in Congress is to say that the requirements of this bill are what the health of the Nation requires, and to challenge polluters to meet them.”) 408 UARG comment at 31. See id . at 18, 29, 49. This comment appears to be a reference to the Supreme Court’s statement in UARG. See Util. Air Regulatory Group v. EPA , 134 S. Ct. 2427, 2444 (2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 486 of 1275 (dispatch shifts and renewable energy), and that recognized that those measures (renewable energy) would also reduce carbon dioxide and thereby address the dangers of climate change. (9) Response to comments concerning building blocks 2 and 3 as precedents. Commenters 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. 409 For example, 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. 410 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

409 Most of the commenters’ concerns over what they viewed as the precedential effects of the building blocks concerned building block 4. Because the EPA is not finalizing building block 4 as part of the BSER, it is not necessary to address those concerns. 410 UARG comment at 2-3.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 487 of 1275 and applications. For example, because the affected EGUs must be able to achieve their emission standards through application of the BSER, the BSER must be something that the EGUs themselves can implement. The affected sources that are the subject of the emission guidelines can employ the BSER to achieve the emission limits that the guidelines prescribe. For the reasons discussed, building blocks 2 and 3 meet the definition of the BSER, as it has been interpreted and applied. As a result, they qualify as part of the basis for the emission limits in the emission guidelines promulgated in this rule. Moreover, as also discussed, the affected EGUs may meet those limits by implementing the BSER, including the measures in building blocks 2 and 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, the application of building blocks 2 and 3 to affected EGUs has a number of unique characteristics that significantly limit their precedential impact. Building blocks 2 and 3 entail the production of the same amount of the same product -- electricity, a highly substitutable product that can be produced using a variety of generation processes -- through*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 488 of 1275 the cleaner (that is, less CO 2 -intensive) processes of shifting dispatch from steam generators to existing NGCC units, and from both steam generators and NGCC units to renewable generators. 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 no capacity for substantial amounts of 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 various reasons, including environmental reasons. As a result, at present, there is a well-established network of business relationships and past practices that supports building blocks 2 and 3. As noted elsewhere, a large segment of steam generators*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 489 of 1275 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 renewable energy. 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.. 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 examples noted above are inapposite for several reasons. Title II standards are based on “the application of technology which the

Administrator determines will be available for the model year...,” which is a narrower standard than the “best system of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 490 of 1275 emission reduction ... adequately demonstrated.” Moreover, the examples appear to be premised on government action (i.e., that a government would “require[e] car owners to shift some of their travel buses, or ... require[e] there to be more electric vehicle purchases”), whereas the measures in building blocks 2 and 3 can be implemented by the affected EGUs. 2. Legal justification for including emissions trading within the BSER. This section provides the legal justification for including trading or averaging within the BSER. 411 a. Background information. Emission trading may take one of two forms, depending on the form of the emission limitation to which the sources are subject. If the emission limitation is an emission rate (expressed, for example, in pounds of CO 2 per MWh), then trading takes the form of buying or selling emission reduction credits (ERCs) that an affected EGU may generate if

its actual emission rate is lower than its allowed emission

rate. If the emission limitation is a mass-based limit (expressed, for example, in the form of a requirement that affected EGUs retire one allowance per ton of CO 2 emissions), then trading takes the form of buying or selling allowances. 412

411 For convenience, in this section, references to “trading” include both trading and averaging. 412 It should be noted that for affected EGUs subject to an emission rate, the BSER also includes purchase of ERCs from (i)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 491 of 1275 (b) Emission trading within the BSER. Emissions trading, as applied in this rule, is within the “system of emission reduction” that is the “best” because it may operate in conjunction with the other types of emission reduction measures that are part of the BSER -- the building blocks -- to assure

that the costs of those measures are lower and are allocated among the affected sources. In this final rule, the EPA has determined that the affected sources, taken as a whole, are able to implement building blocks 1, 2 and 3, and achieve the expected level of emission reduction. The EPA recognizes that it is not optimally efficient for each affected EGU to attempt to implement the measures in each building. Some affected EGUs arelikely to be able to implement the control measures more costeffectively than other EGUs. Moreover, some EGUs may find it more cost-effective to implement other, non-BSER measures to reduce emissions, such as demand-side energy efficiency measures or co-firing. In addition, some sources may find it advantageous to retire. The EPA expects that through any of these avenues, some sources will reduce their emissions by more than they are

existing NGCC units that increase their generation and (ii) renewable energy providers for new renewable energy, but although these ERCs may also be bought and sold, they are not covered by this present discussion of emission trading. Rather, this present discussion is focused on the trading of ERCs generated by an affected EGU whose actual emission rate is below its allowed emission rate, as well as allowances.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 492 of 1275 required, which would enable them to sell ERCs or allowances they no longer need to other affected EGUs whose control costs are higher and who would find it advantageous instead to purchase the ERCs or allowances. In this manner, the opportunity to trade creates incentives that have the effect of focusing controls on the sources for

which those controls are the most cost-effective. 413 The fact that emissions trading reduces overall costs is an important reason why it must be considered within the “system of emission reduction” that is the “best.” In addition, the inclusion of trading is feasible and has no adverse impacts on energy

considerations for the individual affected EGUs or on a nationwide basis, nor does it result in emissions of non-air quality pollutants. Moreover, trading is especially effective for reducing CO2 emissions, due to the ubiquitous nature of CO2 as a pollutant. Of particular importance, a trading program offers an affected EGU additional options for achieving its emission rate: In addition to implementing control measures to reduce its

413 In enacting the cap-and-trade provisions of the Title IV Acid Rain Program in the 1990 CAA Amendments, Congress explicitly recognized that trading reduces overall program costs through the mechanism described in the text accompanying this footnote. The legislative history explained that the trading program was estimated to reduce overall costs by at least 20 percent. Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 493 of 1275 emissions, the source can purchase ERCs or allowances from other affected sources. Because under section 111(a)(1), a standard of performance is defined, in general, as an emission standard that reflects emission limits achievable through the application of the BSER, the fact that a source can rely on trading -- specifically, the acquisition of credits or allowances -- to achieve its emission limits, supports treating trading within

the BSER.Trading is well-established, particularly for fossil fuelfired EGUs. As we discuss next, for the past 25 years, Congress and the EPA have adopted successful emissions trading programs for different air pollutants for these sources. Because trading is so well-established, it is reasonable to expect that states will allow trading as part of the emission standards they may adopt for their CAA section 111(d) state plans. Congress enacted the Acid Rain Program in Title IV of the 1990 CAA Amendments as a nationwide cap–and-trade program for

fossil fuel-fired EGUs to reduce SO 2 emissions. In doing so, Congress expressed its understanding that emission trading would lower overall costs and assure that all the EGUs subject to the requirements would have a mechanism for achieving their emission limits. CAA section 401(b) provides: It is the intent of this subchapter to effectuate such reductions by requiring compliance by affected sources*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 494 of 1275 with prescribed emission limitations by specified deadlines, which limitations may be met through alternative methods of compliance provided by an emission allocation and transfer system. The legislative history elaborates: [T]hrough a system of marketable allowances, the reduction programs established by the title maximize the range of choices sources have for complying with their emissions limitation requirements. An individual source may emit more than required if another source emits less than it, the latter, is permitted to emit. Through this flexibility, the bill minimizes costs and maximizes flexibility and efficiency. The EPA estimates that this added flexibility could reduce the total costs of the program by at least 20 percent. On a regional basis, this may allow areas with substantial reduction obligations and total costs to lower their net costs by producing and selling ‘extra’ reductions (i.e., reductions beyond those they are required to achieve) to sources seeking to emit more than is permitted. At the same time, areas facing growth in the energy demand or units with high emissions control cost on a per ton basis find that purchasing excess emissions reductions from plants in other areas, rather than making on-site reductions, enables them to comply with their emissions limitations at a significantly lower cost. Allowing sources to market ‘extra’ emissions reductions should also yield important environmental benefits as sources will have strong incentives to make greater-than-required reductions earlier than required. Since sources will enjoy maximum flexibility in responding to those incentives, this approach should also stimulate innovation in pollution-control technology and practices. 414 Similarly, in CSAPR, the EPA addressed interstate transport

of SO 2 , NO x , and particulate matter emitted by fossil fuel-fired

414 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 495 of 1275 EGUs by promulgating a tradable allowance system, and stated as

follows: [T]his [trading] approach provides the most flexibility for sources while meeting the [CAA] requirements and protecting public health... EPA believes that the preferred trading remedy will allow source owners to choose among several compliance options to achieve required emission reductions in the most cost effective manner, such as installing controls, changing fuels, reducing utilization, buying allowances, or any combination of these actions. 415 As described above in this section, CSAPR is merely the most recent in a line of EPA interstate transport rules that took into account trading as a method for EGUs to reduce emissions. For example, the NO X SIP Call set state budgets based on a uniform emission standard for EGUs in part because those standards were “based on the adoption of a broad-based trading program” that would allow sources with higher marginal costs to more cost-effectively comply. 416 Similarly, in CAIR, the EPA set state budgets based on cost-effective controls on EGUs and, in evaluating the cost impacts, “assume[d] interstate emissions trading” because of the reasonable likelihood that states and EGUs would use trading as the way to meet emission requirements. 417

415 76 Fed. Reg. at 48272. 416 63 Fed. Reg. 57356, 57399 (Oct. 27, 1998). 417 70 Fed. Reg. 25162, 25196 (May 12, 2005).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 496 of 1275 By the same token, in the 2005 rulemaking the EPA promulgated under CAA section 111(d) to control mercury

emissions from affected EGUs -- the CAMR -- the EPA identified a nationwide cap-and-trade program as part of the BSER, along with add-on controls to reduce mercury emissions. The EPA projected that with a cap-and-trade program, mercury reductions would “result from units that are most cost effective to control,

which enables those units that are not cost effective to use other approaches for compliance including buying allowances, switching fuels, or making dispatch changes.” 418 This program enabled the EPA to set the cap’s stringency at a level commensurate with widespread compliance, whereas if the cap were based solely on the installation of control technologies, the cap would not be cost-effective for the source category. 419 In establishing the Title IV trading program, Congress recognized that fossil fuel-fired EGUs are well-suited to engage in emission trading: “[B]y their business nature,” Congress explained, “utilities appear to be well-suited to create, and to

418 70 Fed. Reg. 28606, 28619 (May 18, 2005). 419 In addition, in a 1995 rulemaking for municipal solid waste incinerators, the EPA also authorized states to allow large municipal waste combustors to average their emission rates and trade NO x emission credits. “Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources; Municipal Waste Combustors,” 60 Fed. Reg. 65,387 at 28616-24, (Dec. 19, 1995).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 497 of 1275 take advantage of, an active market in emissions allowances.” 420In fact, Congress added, “utilities already engage in powerpooling arrangements to ensure maximum flexibility and efficiency in supplying power.” 421 Moreover, Congress added, the allowance system enabled parties to “transfer between them and among themselves pursuant to a wide variety of commercial agreements such as under leases, sales agreements and exchanges between emissions and electric power or capacity.” 422 The Energy Information Agency of the Department of Energy, in its annual report on electric power for the year 2000, noted that allowance purchases were one of the means by which the EGUs

achieved their Title IV emission limits: On January 1, 2000, the electric industry came under Phase II regulations of the [CAA] Amendments of 1990. This Act was primarily designed to reduce power plant emissions, specifically sulfur dioxide and nitrogen oxides. Phase I, which began on January 1, 1995, affected 435 generating units and allowed the release of 2.5 pounds of sulfur dioxide per each million Btu of fuel consumed. Under Phase II, coverage increased to more than 2,000 units, while restrictions on emissions were set at 1.2 pounds of sulfur dioxide per million Btu of fuel consumed. Since 1995, some generators have over complied with Phase I in order to create excess allowances. This has allowed them to delay enacting additional strategies that would be necessary for compliance with Phase II. Strategies that are being used for compliance include fuel switching/ blending, co-firing with natural gas,

420 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 421 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 422 Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 498 of 1275 allowance acquisitions, scrubbers, repowering, and plant retirements. 423 In addition, beginning in 1998, the EPA has promulgated allowance trading programs in a series of rulemakings to reduce interstate transport in the eastern part of the U.S. of SO 2 , NO x , and particulate matter emissions from fossil fuel-fired EGUs in upwind states that jeopardize the ability of downwind states to attain and maintain the NAAQS. 424 States and the EPA have implemented those requirements through SIPs and FIPs under CAA

section 110. In addition, states have adopted allowance-based trading programs to control CO 2 emissions from fossil fired EGUs. 425 These programs have established the structural components of a trading program, including mechanisms to allocate allowances and track their ownership and use, and have operated trading programs, and have thereby demonstrated that a trading program for CO 2 emissions from fossil fuel-fired EGUs can operate effectively.

423 EIA, “Electric Power Annual 2000,” vol. 1 (August 2001) 13 http://www.eia.gov/electricity/annual/archive/vol1/0348001.pdf (emphasis added, citations omitted). 424 For the NO x SIP Call, see 63 Fed. Reg. 57,356, XXXXX (Oct. 27, 1998). For CAIR, see 70 Fed. Reg. 25,162, XXXXX (May 12, 2005) (Clean Air Interstate Rule); For CSAPR, see 76 Fed. Reg. 48,208 XXXX (Aug. 8, 2011) (Cross-State Air Pollution Rule). 425 The RGGI program regulates CO 2 from fossil fuel-fired EGUs. The California AB32 program regulates CO 2 from fossil fuel-fired EGUs and other sources.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 499 of 1275 It should also be noted that states have adopted other emission trading programs -- both rate-based trading programs and allowance trading programs -- that control a range of emissions from a range of sources. In some cases, these state programs have been included as part of SIPs and the EPA has approved them. For example, the South Coast Air Quality Management District adopted the Regional Clean Air Incentives Market (RECLAIM) program in October 1993 to establish a NO x and

SO x emissions cap-and-trade program in the South Coast air basin. RECLAIM, which is codified in SCAQMD Regulation XX (Rules 2000 through 2020), generally applies to stationary sources that emit 4 tons or more per year of NO x or SO x in the year 1990 or subsequent years and establishes emissions caps for NO x and SO x that decline over time. The program was designed to provide

sources with incentives to reduce emissions and advance pollution control technologies by giving sources added flexibility in meeting emission reduction requirements. 426 The EPA approved RECLAIM as a discretionary Economic Incentive

426 See http://www.aqmd.gov/home/programs/business/businessdetail?title=reclaim.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 500 of 1275 program in June, 1998. 427 The EPA has issued comprehensive guidance to states for adopting emission trading programs. 428 3. Reduced generation and the BSER 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, viewing the BSER through either the source-category perspective or the source-specific perspective, we are determining the BSER as the measures included in building block 1, as well as the set of measures included in building blocks 2 and 3, which incorporate reduced generation, along with the purchase of emission reduction credits or allowances. Reduced generation qualifies as part of the BSER because of the unique characteristics of this industry, which tie it closely to the measures in building blocks 2 and 3. The amount of generation from the increased utilization of NGCC units would determine a portion of the

427 63 FR 32621 (June 15, 1998). 428 Environmental Protection Agency, Office of Air and Radiation,“Improving Air Quality with Economic Incentive Programs,” EPA452/R-01-001 (2001). http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 501 of 1275 amount of the generation reduction component of the BSER for affected fossil fuel-fired steam EGUs, and the amount of generation from the use of expanded renewable energy generating capacity that could be provided, would determine a portion of the amount of the generation reduction component of the BSER for all affected EGUs. This section discusses why reduced generation is a part of the BSER under this formulation. a. Background. As noted, for both rate-based and allowance-based state plans, affected EGUs may take a set of actions to comply with their emission standards. An affected EGU may comply with an emission rate ( e.g., a limit on amount of pounds of CO 2 per MWh) by acquiring, through one means or another, credits from lower- or zero-emitting generation (building blocks 2 or 3, respectively) to reduce its actual emission rate. In addition, the affected EGU may reduce its generation, and if it does so, it then needs to acquire fewer of those credits to meet its

emission rate. 429 Under these circumstances, the affected EGU would in effect replace part of its higher emitting generation with lower- or zero-emitting generation. On the other hand, an

429 An affected EGU that is subject to an emission rate, e.g., pounds of CO 2 per MWh generated, cannot achieve that rate simply by reducing its generation (unless it shuts down, in which case it would achieve a zero emission rate). This is because although reducing generation results in fewer emissions, it does not, by itself, result in fewer emissions per MWh generated.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 502 of 1275 affected EGU that is subject to an allowance requirement -- under which it must hold enough allowances to cover its emissions ( e.g., one allowance for each ton of emissions in any year) -- may comply in part by reducing its generation and, thus, its emissions. Therefore, one type of action that an affected EGU may take to achieve either of these emission limits is to reduce its generation. Reduced generation is part of the BSER for affected EGUs for the following reasons, which generally must be understood against the backdrop of the integrated power sector: First, it is part of a “system of emission reduction” within the meaning of the BSER provisions because it is an action within the control of an affected EGU that reduces emissions. Indeed, it is a commonly used method for fossil fuel-fired EGUs to meet CAA obligations. Both Congress and the EPA have relied on it inestablishing other CAA obligations, and there are wellestablished mechanisms for implementing it. Second, it meets the other components of the definition of BSER because it is feasible, results in fewer emissions, is of reasonable cost, does not have adverse implications for energy or non-air quality pollutants, and is adequately demonstrated. Third, in the context of this rule, it would lead to cleaner forms of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 503 of 1275 generation and would not result in adverse impacts on the utility power sector. b. System of emission reduction. Reduced generation is part of the “system of emission reduction” under CAA section 111(d)(1) and (a)(1) for this industry. Reduced generation is encompassed by the terms of the phrase “system of emission reduction” in CAA section 111(a)(1), as a matter of Chevron step 1, because, in accordance with the above-discussed definition of “system,” reduced generation is a “set of things” == which include reduced use of generating equipment and therefore reduced fuel input == that the affected EGU may itself take to reduce its CO 2 emissions. If that phrase is not considered clear by its terms, then, under Chevron step 2, it may reasonably be interpreted to include reduced generation. As noted above, to achieve its emission standard, an affected EGU subject to an emission rate must combine reduced generation with the acquisition of sufficient emission reduction credits (so that it is, in effect,replacing its higher emitting generation with low- or zeroemitting generation), and an affected EGU subject to an allowance requirement must acquire sufficient allowances to cover its remaining emissions. Reduced generation in the amounts contemplated in this rule reduces emissions from the affected sources, but because of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 504 of 1275 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 constantly 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 505 of 1275 transmission lines. The system is planned and designed 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 such as coal, nuclear, renewables and natural gas, as well as demand-side resources. If generation is reduced from one generator, safeguards are in place to ensure that adequate supply is still available to meet demand. 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 theallowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO 2 emitted, explicitly recognized that fossil fuel-fired EGUs could meet this requirement by reducing their generation. In fact, Congress anticipated that fossil fuel-fired EGUs may choose to comply

with the SO 2 emission limits by reducing utilization, and included provisions that specifically addressed reduced utilization. For example, CAA section 408(c)(1)(B) includes requirements for an owner or operator of an EGU that meets the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 506 of 1275

Phase 1 SO 2 reduction obligations and the NO x reduction obligations “by reducing utilization of the unit as compared with its baseline or by shutting down the unit.” 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 the EGUs were expected to rely on to achieve their emission limitations. One example is includes 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. 430 In 1980, the EPA promulgated a regulatory definition of BART: “an emission limitation based on the degree of reduction achievable through the best system of continuous emission reduction for each pollutant which is emitted by an existing stationary facility.” 431 Both the statutory factors and the regulatory definition resemble the definition of the BSER under CAA section 111(a)(1). In their regional haze SIPs,

430 CAA section 169A(g)(2). 431 40 C.F.R. § 51.301.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 507 of 1275 several states determined that BART included reduced generation, in the form of either capacity limitations or plant closures. For example, the State of Oklahoma determined that BART for the

SO 2 emissions from two coal-fired boilers at a power plant contained several elements, including “interim emission limits, the installation of Dry Sorbent Injection (DSI) and a fabric filter baghouse, phased reductions in capacity utilization , and enforceable deadlines by which [the boilers] must be shut down entirely .” 432 Similarly, the State of New York determined that

BART for the NO X emissions from two coal-fired boilers that served as peaking units was caps on baseline emissions rates and annual capacity factors of 5 percent and 10 percent, respectively. 433

There have been numerous other instances in which fossil fuel-fired EGUs have reduced their generation, or placed limits on their generation, in order to achieve, or obviate, emission standards. In fact, it is common for these EGUs to 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

432 78 FR 51,686, 51,690 (Aug. 21, 2013) (emphases added). 433 77 Fed. Reg. 24,794, 24,810 (Apr. 25, 2012).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 508 of 1275 Title V programs (including Title V fees), and avoiding triggering HAPs 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 potential to emit a pollutant at a level that is equal to or greater than specified thresholds are subject to major source requirements. 434 A source may voluntarily obtain a synthetic minor limitation –- that is, a legally and practicably enforceable restriction that has the effect of limiting emissions below the relevant level -- to avoid triggering a major stationary source requirement. 435

434 See, e.g., CAA sections 112(a)(1), 112(d)(1), 165(a), 169(1), 172(c)(5), 173(a) &(c), 501(2), 502(a), 302(j). 435 See, e.g., Memorandum from Terrell Hunt, Assoc. Enforcement Counsel, U.S. EPA, & John Seitz, Director, Stationary Source Compliance Div., U.S. EPA, Guidance on Limiting Potential to Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), available at http://www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdf (“Restrictions on production or operation that will limit potential to emit include limitations on quantities of raw materials consumed, fuel combusted, hours of operation, or conditions which specify that the source must install and maintain controls that reduce emissions to a specified emission rate or to a specified efficiency level.”) (emphasis added).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 509 of 1275 Such synthetic minor limits may be based on restrictions on the hours of operation, as provided in EPA’s regulations defining “potential to emit,” as well as on air pollution control equipment. “Potential to emit” is defined, for instance, in the regulations for the PSD program for permits issued under federal authority as: “the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment

and restrictions on hours of operation ... shall be treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable,” 436 or “legally and practicably enforceable by a state or local air pollution control agency." 437 The regulations for other air programs similarly recognize that potential to emit may be limited through restrictions on hours of operations in their corresponding definitions of “potential to emit.” 438 These

436 40 CFR 52.21(b)(4)(emphasis added). 437 John Seitz, Director, Office of Air Quality Planning and Standards, and Robert Van Heuvelen, Director, Office of Regulatory Enforcement, Release of Interim Policy on Federal Enforceability of Limitations on Potential to Emit, at 3 (Jan. 22, 1996), available at http://www.epa.gov/region07/air/nsr/nsrmemos/pottoemi.pdf. 438 See 40 CFR 51.166(b)(4) (addressing SIP approved PSD programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 510 of 1275 regulatory provisions make clear that restrictions on potential to emit include both “air pollution control equipment” and “restrictions on hours of operation,” and indicate that these are equally cognizable means of restricting emissions to comply with, or avoid, CAA requirements. 439 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, nitrogen oxides and sulfur dioxide below the PSD threshold of 250 tpy. 440 As another example, Sunbury

programs), 70.2 (addressing title V operating permit programs), and 63.2 (addressing hazardous air pollutants). 439 See, e.g., 52.21(b)(4). 440 See Final Operation Permit No. 436123380-P10 for Manitowoc Public Utilities - Custer Street (Wis. Dept. Nat. Res., 8/19/2013), Condition ZZZ.1.a(1) at p. 9 (Limiting potential to emit) and n. 11 (“These conditions are established so that the potential emissions for volatile organic compounds will not exceed 99 tons per year and potential emissions for carbon monoxide, nitrogen oxides and sulfur dioxide emissions from the facility will not exceed 249 tons per year.”). See also Analysis and Preliminary Determination for the Renewal of Operation Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/21/2013) at p. 5 (noting that the “existing facility is a major source under Part*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 511 of 1275 Generation LP in Pennsylvania obtained a minor new source preconstruction permit, called a plan approval, for a repowering project from the Pennsylvania Department of Environmental Protection in 2013 that limited the hours of operation of three combined cycle combustion turbines that were planned for construction in order to remain below the significance threshold

for GHGs. 441 There are several ways that an affected EGU may implement reduced utilization. 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

70 because potential emissions of sulfur dioxide, nitrogen oxides and carbon monoxide exceed 100 tons per year. The existing facility is a minor source under PSD and an area source of federal HAP” and further noting that after renewal, “the facility will continue to be a major source under Part 70 because potential emissions of sulfur dioxide, nitrogen oxides and carbon monoxide exceed 100 tons per year. The facility will also continue to be a minor source under PSD and an area source of federal HAP.”). 441 See Plan Approval No. 55-00001E for Sunbury Generation LP (Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 24, 32 and 40 (limiting turbine units to operating no more than 7955, 6920, or 8275 hours in any 12 consecutive month period depending on which of three turbine options was selected); Memorandum from J. Piktel to M. Zaman, Addendum to Application Review Memo for the Repowering Project (Pa. Dept. Env. Protection, 4/1/2013) at p. 2 of 10 (noting that source had “calculated a maximum hours per year (12 consecutive month period) of operation for the sources proposed for each of the turbine options in order to remain below the significance threshold for GHGs.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 512 of 1275 impacts, which requires it to raise its bid price, so that the EGU is dispatched less]. c. Other BSER requirements and considerations. Reduced generation meets the criteria to be considered part of the “best” system of emission reduction that is “adequately

demonstrated.” It is a feasible method of emission control because an affected EGU may reduce its generation by operating fewer hours, and may implement reduced generation through the methods just described. In addition, reduced generation results in fewer emissions, is of reasonable cost, and does not have adverse implications for energy use at the affected EGUs or result in non-air quality pollutants.Furthermore, reduced generation as a means for fossil fuelfired EGUs to reduce emissions is adequately demonstrated. As noted above, Congress recognized its use in enacting Title IV, the EPA has established emission limits in other rulemakings based in part these EGUs’ ability to achieve those limits by reducing generation, and in numerous instances, these EGUs have accepted limits on their generation in permits. At the levels proposed, these measures 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 513 of 1275 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 choose or be required to reduce their CO 2 emissions by means of reducing their generation. 442 d. Impacts on utility power sector. Reduced generation by affected EGUs, in the amounts that affected EGUs may rely on to comply with this rule, will not have adverse effects on the utility power sector. In light of the emission limits of this rule, 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 under this rule, and occurring over the lengthy time frames provided under this rule,will result in replacement generation that generally is loweror zero- emitting. Mechanisms are in place in both regulated and deregulated electricity markets to assure that substitute

442 It should be noted that in light of the low current and projected near term prices for natural gas, market forces may lead investors to choose to build new NGCC units, rather than new renewable resources. This result would not call into question the technical feasibility of a BSER that included reductions in fossil fuel-fired generation by the amount of a specified amount of new renewable resources. This is because under these circumstances, the fossil fuel-fired generators could still reduce their generation without causing reliability or other problems in the electric power system.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 514 of 1275 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. Because of the availability of the measures in building blocks 2 and 3, the proposed levels of reduced generation are of reasonable cost for the affected source category and the nationwide electricity system, do not jeopardize reliability, and result in the appropriate amount of

emission reductions. All these results come about because the operation of the electrical grid through integrated generation, transmission, and distribution networks creates fungibility for electricity and electricity services, which allows decreases in generation at affected fossil fuel-fired steam EGUs to be replaced by increases in generation at affected NGCC units (building block 2) and allows decreases in generation at allaffected EGUs to be replaced by increased generation at zeroemitting EGUs (building block 3) Further, this fungibility increases over longer timeframes with the opportunity to invest in infrastructure improvements, and as noted elsewhere, this rule provides an extended state plan and source compliance horizon. These characteristics of the integrated electricity system assure that reduced generation in specified amounts meets*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 515 of 1275 the criteria to qualify as the “best” system of emission

reduction. e. Comments concerning limiting principles. A commenter stated that “an interpretation of [‘system of emission reduction’] that relies primarily on reduced utilization has no clear limiting principle.” 443 We disagree with this concern, for the following

reasons. As discussed, in this final rule, we are identifying the BSER as the combination of the three building blocks. Buildings 2 and 3 entail substitution of lower- or zero-emitting generation for higher-emitting generation, and a component of that substitution is reduced generation. Accordingly, our identification of the BSER in this final rule does not “rel[y] primarily” on reduced utilization as the BSER. Moreover, as also discussed, building blocks 2 and 3, as well as reduced generation, meet the requirements for the BSER, and therefore may serve as the basis for the emission guidelines in this rule, in accordance with CAA section 111(d)(1) and (a)(1). By the same token, reduced generation is one of several methods that affected EGUs may employ to achieve or help achieve the emission limits established by these emission guidelines. The commenter’s concerns over a perceived lack of a limiting

443 EEI comment, at 284.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 516 of 1275 principle cannot be taken to mean that reduced generation cannot be considered to be a component of the BSER or constitute a

method for affected EGUs to achieve their emission limits. Moreover, reduced generation, as applied to affected EGUs in this rule, is limited in a number of respects. The amount of reduced generation is prescribed. It 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. Moreover, 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 517 of 1275 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 as a “system of emission reduction” is not easily transferrable to another industry. 4. The EPA authority to determine the BSER. In this section, we explain why the EPA, and not the states, has the authority to determine the BSER and, therefore, the amount 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, state plans were required to establish “emission

standards” -- an undefined term -- rather than “standards of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 518 of 1275 performance,” a term that was limited to CAA section 111(b). 444 Prior to this change, however, the EPA issued regulations implementing CAA section 111(d) in 1975. 445 These regulations established a cooperative framework, similar to that under CAA section 110, where the EPA first develops “emission guidelines” for source categories -- 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” -- and states then submit implementation plans to regulate any existing sources. 446 The 1975 implementing regulations carefully considered the allocation of responsibilities as between the EPA and the states in regulatory actions under CAA section 111(d), and concluded that the EPA had the responsibility of determining the amount of emission limitation from the source category, while the states had the responsibility of assigning emission requirements to

their sources that assured that amount of emission limitation. In issuing the regulations, the EPA explained “that some

444 See “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 Stat. 1676, 1683-84 (Dec. 31, 1970). 445 See “State Plans for the Control of Certain Pollutants From Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 446 See ”State Plans for the Control of Certain Pollutants From Existing Facilities,” 40 F.R. 53340 (Nov. 17, 1975).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 519 of 1275 substantive criterion was intended to govern not only the Administrator’s promulgation of standards but also [her] review of state plans.” 447 The EPA added, “it would make no sense to interpret [CAA] section 111(d) as requiring the Administrator to base approval or disapproval of state plans solely on procedural criteria. Under that interpretation, states could set extremely lenient standards -- even standards permitting greatly increased emissions -- so long as [the] EPA’s procedural requirements were

met.” 448 The EPA concluded that “emission guidelines, each of which will be subjected to public comment before final adoption, will serve [the] function” of providing substantive criteria “in advance to the states, to industry, and to the general public” to aid states in “developing and enforcing control plans under [CAA] section 111(d).” 449 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). Currently, standards of performance are defined as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through

447 ”State Plans for the Control of Certain Pollutants From Existing Facilities,” 40 F.R. 53340, 53342 (Nov. 17, 1975). 448 ”State Plans for the Control of Certain Pollutants From Existing Facilities,” 40 F.R. 53340, 53343 (Nov. 17, 1975). 449 ”State Plans for the Control of Certain Pollutants From Existing Facilities,” 40 F.R. 53340, 53343 (Nov. 17, 1975).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 520 of 1275 the application of the best system of emission reduction which

... the Administrator determines has been adequately demonstrated.” (Emphasis added.) 450 By its terms, this provision provides that the EPA has the responsibility of determining whether the “best system of emission reduction” is “adequately demonstrated.” While this provision does not explicitly assign the responsibility to the EPA of identifying the “best system of emission reduction” in the first instance to the EPA, it is a logical inference that Congress intended that interpretation in light of the fact that the Administrator must make the “adequately demonstrated” determination. Even if the provision is considered to be silent on that question, the EPA reasonably interprets the provision under Chevron step 2 to assign that responsibility of identifying the “best system of emission

reduction” to the EPA for the same reasons as discussed in the EPA’s explanation of the implementing regulations. In addition, in the legislative history of the 1977 CAA Amendments, Congress endorsed the overall approach of the implementing regulations, which lends further credence to the

450 As noted, the 1977 version of CAA section 111(a)(1) differed from the current version, which was adopted in the 1990 CAA Amendments, but those differences do not call into the question the proposition that the EPA has the responsibility of determining the “best system of emission reduction ... adequately demonstrated” and, therefore, the amount of required emission limitation from the source category.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 521 of 1275 proposition that the EPA has the responsibility of 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 guidelines as to what the best system for each category of existing sources is.” (Emphasis added.) 451 States, on the other hand, “would be responsible for determining the applicability of such guidelines to any particular source or sources.” (Emphasis added.) 452 The use of the term “guidelines,” which does not expressly appear in CAA section 111(d), indicates Congress was aware of and approved of the overall approach the EPA promulgated in its implementing regulations for determining

the BSER. Commenters argued that the states should be given the authority to determine the best system of emission reduction and, therefore, the amount of emission limitation from their sources. For the reasons described above, this is an incorrect interpretation of CAA section 111(d)(1) and (a)(1). 5. Relative stringency of requirements for existing sources and new and modified sources. Commenters also objected that the

451 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 452 H.R. Rep. No. 95-294, at 195 (May 12, 1977).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 522 of 1275 proposed CAA section 111(d) standards are more stringent than the standards for new, modified or reconstructed sources, and they assert that setting section 111(d) standards that are more stringent than 111(b) standards would be illogical, contrary to precedent, contrary to the intent of the remaining useful life exception, and arbitrary and capricious. 453 We disagree with

these comments. Comparing the control requirements of the two sets of rules -- CAA section 111(d) and 111(b) –- is an “apples-to-oranges” comparison and, as a result, it is not possible to conclude that the 111(d) requirements are more stringent that the 111(b) requirements. Most importantly, the two sets of rules have significantly different compliance times and compliance periods. The compliance time for the CAA section 111(b) rule for both new and modified sources is immediately upon construction or modification and, in fact, by operation of section 111(e) and (a)(2), new or modified sources that commenced construction prior to the effective date of the section 111(b) rule must also be in compliance upon the effective date of the rule. In contrast, the compliance time for the CAA section 111(d) rule

453 ACC et al. (Associations) comments at 40, Luminant comments at 89.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 523 of 1275 does not begin until 7 years after promulgation of the rule, when the interim compliance period begins in 2022, and the final compliance time is not until 2030. Moreover, the compliance period for the interim requirements is 8 years. This longer compliance time and compliance period for existing sources accommodates a requirement that, on average, those sources have a lower nominal emissions limit than the requirements for new or modified sources, which those sources must comply with immediately. Indeed, it should be noted that under the schedule required under CAA section 111(b)(1)(B), the EPA would be required to review and revise the CAA section 111(b) rule shortly after the interim compliance time for the CAA section 111(d) rule begins in 2022, and well before the final compliance date in 2030, which heightens the significance of the different compliance period. In addition, for any individual source, the CAA section 111(d) rule includes more flexible means of compliance. The state may assign emission limits differently than the EPA’s guidelines, and may be expected to authorize emissions trading or averaging. These flexibilities are not included in the CAA section 111(b) rule, rather, new and modified EGUs must meet the

emission standard at all times. This distinction is another*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 524 of 1275 reason why the CAA section 111(d) rule cannot be said to be more stringent than the CAA section 111(b) rule. 6. Relationship between a source’s implementation of building blocks 2 and 3 and its emissions. 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 may achieve that rate 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 those things 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 result 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, due to the fuel costs, than, at least, zero-emitting generation. Displacement of higher-emitting generation will lower overall CO 2 emissions from the source category of affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 525 of 1275 If an affected EGU implements building block 2 or 3 by reducing its generation, it will reduce its own emissions. However, it may invests in other types of building block 2 or 3 measures that do not, in-and-of-themselves, reduce the amount of its own emissions or, for that matter, its own generation. This is because the interconnected grid includes numerous generators, and electricity generation becomes undifferentiated the moment it is dispatched, so that it is not possible to trace electricity to any particular generator. Moreover, absent a limit on generation, such as, for example, one included in a permit, an affected EGU’s generation generally depends on where it falls on the dispatch curve. Even so, implementation of building blocks 2 and 3 will reduce CO 2 from some affected EGUs,

and therefore reduce CO 2 on a source category-wide basis. This outcome is 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 526 of 1275 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 527 of 1275 The application of the building blocks has an impact that is similar to that of a 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. 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) due to 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. 7. Approach to subcategorization. As noted above, in this rule, we are treating all fossil fuel-fired EGUs as a single category, and, in the emission guidelines that we are promulgating with this rule, we are treating steam EGUs and combustion turbines as separate subcategories. We are determining the BSER for steam EGUs and the BSER for combustion turbines, and applying the BSER to each subcategory to determine a performance rate for that subcategory. We are not further subcategorizing among different types of steam EGUs or combustion turbines. This approach is fully consistent with the provisions of section 111(d), which simply require the EPA to determine the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 528 of 1275 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 454 and then to regulate new sources within each such source category, 455 and which grant the EPA discretion whether to subcategorize new sources for purposes of determining the BSER. 456 Subcategorization may be appropriate when certain types of sources could not achieve the same emission limit as other types of sources, but here, each affected EGU can achieve the performance rate by implementing the BSER. Specifically, as noted, each affected EGU may take a range of actions –- some of which depend on whether the state imposes an emission rate or a mass limit -- including investment in the building blocks, replaced or reduced generation, and emissions trading. 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 energy efficiency measures. Such compliance options

454 CAA section 111(b)(1)(A). 455 CAA section 111(b)(1)(B). 456 CAA section 111(b)(2).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 529 of 1275 may also indirectly help affected sources 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. Of course, a state retains great flexibility in assigning standards of performance to its affected EGUs and 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. 8. Reasons that this rule is within the EPA’s statutory authority and does not represent over-reaching. 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, including investment in renewable energy and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 530 of 1275 implementation of a broad range of state and utility demand-side energy efficiency programs. Commenters also emphasized that with the proposed portfolio approach, the rule would impose federally enforceable requirements on a wide range of entities that do not

emit CO 2 and have not previously been subject to CAA regulation. Commenters cite the U.S. Supreme Court’s statements in Utility Air Regulatory Group v. EPA (UARG) 457 that caution an agency against interpreting its statutory authority in a way that “would bring about an enormous and transformative expansion in [its] regulatory authority without clear congressional authorization,” and that add, “When an agency claims to discover in a long-extant statute an unheralded power to regulate ‘a significant portion of the American economy,’ ... we typically greet its announcement with a measure of skepticism.” 458 Commenters assert that in this rule, the EPA is taking the

actions that the UARG opinion cautioned against. For the reasons discussed below, these comments are incorrect and misunderstand fundamental aspects of this rule. In addition, the EPA is not finalizing either building block 4 or the portfolio approach. In this rule, the EPA is following the same approach that it uses in any rulemaking under CAA section 111(d), which is

457 134 S. Ct. 2427 (2014). 458 Utility Air Regulatory Group v. EPA , 134 S. Ct. 2427, 2444 (2014) (citations omitted).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 531 of 1275 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 emission rate for steam-generating EGUs and a uniform emission rate for combustion turbines, and the EPA is translating those rates into a combined emission rate and equivalent mass limit for each state. These emission guidelines serve as the guideposts for state plan requirements. The states, in turn, promulgate emission standards and, in doing so, retain significant flexibility to either promulgate the emission rates in the guidelines, promulgate equivalent rates, or promulgate the equivalent mass limits. The sources, in turn, are required to comply with their emission limits, and may do so through any means they choose. 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 limitations. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 532 of 1275 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, rangingfrom -- depending in part on whether the state imposes a ratebased or mass-based emission limit -- implementation of demandside energy efficiency measures to co-firing. Moreover, 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, not only is the EPA not requiring that the states regulate non-affected EGUs, the EPA is not authorizing states to include in their CAA 111(d) plan regulations covering non-affected EGUs. It is certainly true that compliance with these air pollution controls will have costs, and those costs will affect the electricity sector by discouraging fossil fuel-fired electricity and encouraging alternative means of generating electricity. But for affected EGU, 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. This basic fact that the EPA regulations of air pollutants from affected EGUs invariably affect the utility sector is well-recognized. In*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 533 of 1275 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. 459 The Courts have recognized that, too. The U.S. Supreme Court, in its

2011 decision that the CAA and the EPA actions it authorizes displace any federal common law right to seek abatement of CO 2 emissions from fossil-fuel fired power plants, emphasized that

CAA section 111 authorizes the EPA – which the Court identified as the “expert agency” – to regulate CO 2 emissions from these

459 The D.C. Circuit acknowledged this legislative history in Sierra Club v. EPA , 657 F.2d 298, 331 (D.C. Cir. 1981). There, the Court stated: The legislative history clearly supports our reading of amended section 111 as authorizing EPA to balance long term national and regional impacts of alternative standards. 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.” [Citing CAA Conference Report: Statement of Intent; Clarification of Select Provisions, 123 Cong. Rec. 27071 (1977), 3 L.H. at 324 (referring to H.R.Rep.No.95-294 , 95th Cong., 1st Sess. 188 (1977), at 183-95, 4 L.H. at 2651-62, Remarks of Senator Muskie introducing S. 252 for debate, 123 Cong.Rec. 18018 (1977), 3 L.H. at 717.] 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. [Citing S.Rep.No.95-127, 95th Cong., 1st Sess. (1977), 3 L.H. 1371; H.R.Rep.No.95- 294 , 95th Cong., 1st Sess. 188 (1977), 4 L.H. 2465.]*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 534 of 1275 sources in a manner that balances “our Nation’s energy needs and the possibility of economic disruption:” 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 C.F.R. § 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 C.F.R. § 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 jobthan individual district judges issuing ad hoc, caseby-case injunctions. 460

460 American Electric Power v. Connecticut , 131 S. Ct. 2527, 2539-40 (2011).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 535 of 1275 Similarly, the D.C. Circuit, in its 1981 decision upholding the

EPA’s rules to reduce SO 2 emissions from new coal-fired EGUs under the version of CAA section 111(b) adopted in the 1977 CAA Amendments, stated: [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. 461

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.” 462 This rule has “economic, environmental, and energy” impacts, as Congress and the Courts expect in a CAA

461 Sierra Club v. EPA , 657 F.2d 298, 330 (D.C. Cir. 1981). 462 Sierra Club v. EPA , 657 F.2d 298, 406 (D.C. Cir. 1981). The Court supported this statement with a lengthy quotation from a scholarly article, which stated, in part:

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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 536 of 1275 section 111 rule, but those impacts do not mean that the EPA is precluded from promulgating the rule. As noted above, in this rule, to control CO 2 emissions from affected EGUs, the EPA first considered more traditional air pollution control measures, including supply-side efficiency improvements, fuel-switching (for CO 2 emissions, that entails cofiring with natural gas), and add-on controls (for CO 2 emissions, that entails CCS). However, it became apparent that even if the

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 meterological 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.

Id. at 406 n. 526.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 537 of 1275

EPA could have finalized those controls as the BSER 463 and established the same uniform rates, the affected EGUs would rely on less expensive ways to achieve their emission limits. Specifically, instead of relying on co-firing and CCS, the affected EGUs generally would replace their generation with lower- or zero-emitting generation– the measures in building blocks 2 and 3 -- because those measures are significantly less expensive and already well-established as pollution control measures. Indeed, some affected EGUs have stated that while they oppose including in the BSER generation shifts to lower- or zero-emitting sources (or, as proposed, demand-side energy efficiency), they request that those measures be available for compliance, which indicates their interest in implementing those

measures. 464 We expect that many sources will choose to comply with their emission limits through the measures in building blocks 2 and 3 (as well as 4), but contrary to the assertions of some

463 For the reasons explained, we did not finalize those measures because significantly less expensive control measures -- building blocks 2 and 3 -- are available for these affected EGUs. 464 See the proposal for this rule, 79 FR at 34888 (“during the public outreach sessions, stakeholders generally recommended that state plans be authorized to rely on, and that affected sources be authorized to implement, re-dispatch, renewable energy measures, and demand-side energy efficiency measures in order to meet states’ and sources’ emission reduction obligations.”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 538 of 1275 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, as discussed elsewhere, 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. 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 UARG

decision. In UARG , the U.S. Supreme Court struck down the EPA’s interpretation of the PSD provisions of the CAA that had the effect of applying the PSD requirements to large numbers of small sources that previously had not been subject to PSD and with respect to which, according to the Court, the EPA acknowledged that Congress did not intend be subject to the PSD*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 539 of 1275 requirements. 465 Commenters appear to interpret this decision to preclude the EPA from including at least building block 3 in the BSER because it includes measures that involve entities (such as renewable energy developers) that do not emit CO 2 and have not previously been subject to the CAA. However, in this rule, the EPA is not attempting to subject any entity other than the affected EGUs in the source categories to CAA section 111 requirements. As discussed below, the EPA is not finalizing the proposed portfolio approach, under which states were authorized to include, in their CAA section 111(d) state plans, requirements on entities other than affected EGUs. Thus, this final rule does not require or authorize the states to include entities other than affected EGUs in their CAA section 111(d) state plans, and as a result, those entities will not come under CAA jurisdiction and the parts of the economy that they represent will not be regulated by the EPA.C. Building Block 1—Efficiency Improvements at Affected CoalFired Steam EGUs The first category of approaches to reducing CO 2 emissions

at affected fossil fuel-fired EGUs consists of measures that reduce the carbon intensity of generation at individual coal-

465 Util. Air Regulatory Group v. EPA , 134 S. Ct. 2427, 2443 (2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 540 of 1275 fired steam EGUs by improving their heat rate. Heat rate improvements are changes implemented at an EGU that increase the efficiency with which the EGU converts fuel energy to electric energy, thereby reducing the amount of fuel needed to produce the same amount of electricity and consequently lowering the

amount of CO 2 produced as a byproduct of fuel combustion. Heat rate improvements yield important economic benefits to affected sources by reducing their fuel costs. 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. In 2012, the generation-weighted average annual heat rate of domestic coal-fired EGUs was approximately 9,732 Btu per net kWh. 466 Because an EGU’s CO 2 emissions are driven primarily by the amount of fuel consumed, improving (i.e., decreasing) heat rate at a coal-fired EGU inherently reduces carbon-intensity. 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

466 Similarly, in 2012, the generation-weighted average annual heat rates for coal-fired EGUs in each interconnection were 9,700 Btu per net kWh (Eastern); 9,888 Btu per net kWh (Western); and 9,789 Btu per net kWh (Texas).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 541 of 1275 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 (e.g., a unit is unlikely to dramatically increase or decrease in size). Our methodology for determining the amount of heat rate improvement appropriately included in the BSER as building block 1 is discussed in the next section, below. 1. Summary of measures comprising the BSER in building block 1 a. Measures under building block 1 - heat rate improvements. 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 [Docket ID No. EPA-HQ-OAR-2013-0602]. Based on these public comments, we have refined the statistical analyses used in the proposal to identify the potential heat rateimprovement that can be achieved on average by affected coalfired 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 542 of 1275

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 (i.e., hourly operating level as a percentage of nameplate capacity) conditions. The second approach analyzed the difference between an EGU’s average gross heat rate and its best historical gross heat rate performance. We proposed that, on a nationwide basis, affected coal-fired EGUs should be able to achieve 6-percent heat rate improvement: 4-percent improvement from best practices, and an additional 2-percent improvement from equipment upgrades. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 543 of 1275 duct leakage controls. Based on commenters’ concerns over the potential for double-counting, the EPA has decided not to add a separate equipment upgrade component to its estimate of heat rate improvement potential. Nonetheless, we remain confident that additional equipment upgrades (including measures that are unambiguously equipment upgrades, such as turbine overhauls) are possible at many coal-fired EGUs, as supported by numerous commenters, the Sargent & Lundy study 467 (S&L) and other industry reports and studies, many of which are referenced in the TSD developed for the proposed rule. 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

467 Sargent and Lundy 2009, Coal-Fired Power Plant Heat Rate Reductions, SL-009597, Final Report, January 2009, Docket ID No. EPA–HQ–OAR–2013–0602-XXXX, available at: http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 544 of 1275 improvement regionally, within the Eastern, Western and Texas

Interconnections. 468 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 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 2 emission rate. As in the proposal, we used more than one analytical method to evaluate the opportunity for EGUs to reduce their CO 2 emissions through heat rate improvements. Our final methodology uses three different analytical approaches based on refinements of the two approaches described at the proposal stage. We call these final approaches: (1) the “efficiency and consistency improvements under similar conditions” approach; (2) the “best historical average performance” approach; and (3) the “best historical average performance under similar conditions”

468 The geographic area within the Texas Interconnection generally corresponds to the portion of the state of Texas covered by ERCOT (the Electric Reliability Council of Texas). Additional portions of the state of Texas are located within the Eastern and Western Interconnections.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 545 of 1275 approach. As described below and in the TSD, each approach provides an independently reasonable way to estimate the potential for heat rate improvements by EGUs in each region. However, rather than select a potential heat rate improvement value supported by one or only some of these independently reasonable analytical approaches, we conservatively based our final determination for each region on the value for that region supported by all three approaches. The first approach, referred to here as 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 ( o F) range in ambient temperature (from -20 o F to greater than 110 o F), and a 10-percent range in capacity factor (from 0 percent to greater than 110 percent 469 ). Thus, for example, one bin might contain all of an EGU’s hourly gross heat rate data generated during the

469 Because an EGU’s rated nameplate capacity is based on a maximum continuous rating, EGUs may operate for periods of time “over” 100 percent of their capacity factor. The EPA’s dataset of hourly operating data reflected some such instances.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 546 of 1275 11-year study period while that EGU was operating at 80- to 89- percent capacity while ambient temperatures were between 70 o F and

79 o F. As we explained at proposal and as discussed further in the 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 (i.e., we set the benchmark at the 10th percentile hourly gross heat rate value) during any two-year period. 470 We compared the hourly gross heat

470 As described below, we also conducted this regionalized approach using a benchmark based on the best hourly gross heat rate accounting for outliers during any one-year period. See the TSD for more details.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 547 of 1275

rate data within each bin to the EGU’s benchmark value. As in the proposal, within each bin we assessed the effect on heat rate of improving the consistency of that EGU by reducing hourly gross heat rate values that were greater than the benchmark by a percentage of the distance between each of those higher hourly values and the benchmark. We refer to this percentage improvement value as the “consistency factor,” because applying it results in values for heat rate that are marginally more

consistent with the EGU’s benchmark for that bin. Based on engineering judgement, in our proposal we selected a consistency factor of 30 percent after evaluating the heat rate improvement that would result from applying consistency factors of 10, 20,30, 40 and 50 percent of the distance between those lessefficient hourly gross heat rate values and the benchmark. For our final analysis under this approach, we refined the consistency factor based on a statistical assessment of the overall variability of heat rate in that EGU’s region, as

described in the TSD. 471 As in the proposal, we applied the

471 For the Eastern Interconnection, the consistency factor is 38.1 percent. For the Western Interconnection, the consistency factor is 38.4 percent. For the Texas Interconnection, the consistency factor is 37.1 percent. Conducting this analysis on a nationwide basis would have resulted in application of a consistency factor of 38.2 percent. As described below, we also conducted this regionalized approach using consistency factors determined based on one-year figures. See the TSD for more details.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 548 of 1275 consistency factor to each bin of each EGU’s hourly gross heat rate data, and averaged the result across all bins in that EGU’s matrix, giving us marginally improved gross heat rate for that EGU during the 11-year period from 2002 to 2012. We then compared the improved gross heat rate for each EGU to its actual 2012 historic average gross heat rate. We chose 2012 as the year of comparison because 2012 was the latest year for which the EPA had data at the time of the proposal, and because using the most recent data reflects the EGU’s current operating level and accounts for improvements the EGU may have undertaken over the 11-year study period. 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 are at least capable of reducing their CO 2 emissions by improving heat rate 4.3 percent in the Eastern Interconnection, 2.1 percent in the Western Interconnection, and 2.3 percent in the Texas

Interconnection. 472

472 Conducting this analysis on a nationwide basis would have resulted in a finding that EGUs nationwide are capable on average of reducing their CO 2 emissions by improving heat rate 4.0 percent. See the table in this section and the TSD for the results of this approach using benchmarks and consistency factors based on one-year averages.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 549 of 1275 In addition to the statistical approach described above, we employed a “best annual 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. 473 We then calculated the differences across all EGUs in a region to determine the potential heat rate improvement that would result if, in 2012, each EGU had performed at the best two-year rolling average gross heat rate that the EGU achieved between 2002 and 2012. Under this analysis of historical gross heat rate, we determined that it would be reasonable to conclude that the average heat rate improvement potential from best practices and equipment upgrades is at least 4.9 percent in the Eastern Interconnection, 2.6 percent in the Western Interconnection and 3.1 percent in the Texas

Interconnection. 474 Our third and final approach, the “best annual performance under similar conditions” approach, combines aspects of the

473 As described below, we also conducted this regionalized approach using each EGU’s best one-year rolling average. See the TSD for more details. 474 Conducting this approach on a nationwide basis would have resulted in a finding that EGUs nationwide are capable on average of reducing their CO 2 emissions by improving heat rate 4.6 percent. As described below, we also conducted this regionalized approach using one-year averages. See the TSD for more details.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 550 of 1275 first 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 for each of the 168 ambient temperature-capacity factor bin. 475 Similar to the “best historical average performance” approach, to calculate the potential heat rate improvement, the EPA then compared eachEGU’s 2012 gross heat rate for each of the ambient temperaturecapacity factor bins to the EGU’s best two-year gross heat rate for the corresponding bin. Accounting for differences in ambient temperature and capacity factor, we determined that under this analytical approach the average heat rate improvement potential from best practices and equipment upgrades was at least 5.3 percent in the Eastern Interconnection, 3.1 percent in the Western Interconnection and 3.5 percent in the Texas

Interconnection. 476

475 As described below, we also conducted this approach using one-year averages for each EGU instead of two-year averages. See the TSD for more details. 476 Conducting this approach on a nationwide basis would have resulted in a finding that EGUs nationwide are capable on average of reducing their CO 2 emissions by improving heat rate 5.0 percent.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 551 of 1275 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. 477 However, because our conservative overall methodology adopts the lowest value that is identified for a region by any of our reasonable analytical approaches, the inherently less conservative results obtained with one-year averaging periods (reproduced below) could not influence the outcome of our methodology as a whole. Overall, applying these three analytical approaches resulted in six heat rate improvement values generated for each region, each of which represents a reasonable estimate of the potential for heat rate improvements by EGUs in that region. Those values ranged from 4.3 to 6.9 percent in the Eastern Interconnection, from 2.1 to 4.7 percent in the Western Interconnection, and from 2.3 to 4.9 percent in the Texas Interconnection. In all three regions, the most conservative values were generated using the “efficiency and consistency improvements under similar conditions” approach with two-year averaging periods and consistency factors. As shown in the Table 6, the values produced by that approach were the minimum values produced by any of the three approaches:

477 The TSD describes in more detail our rationale for using oneand two-year averaging periods in our analytical approaches and methodology as a whole.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 552 of 1275 **Table 6. Heat Rate Improvement Potential by Region and Averaging Period.** 

Analytical approach Heat rate improvement potential (percent) by region and averaging period

**Western Texas**  **Eastern 1**  **year 2**  **year 1**  **year 2**  **year 1**  **year 2**  **year** Efficiency and consistency improvements under similar conditions 3.5% 2.1%* 3.7% 2.3%* 5.6% 4.3%*

Best annual performance 4.1% 2.6% 4.2% 3.1% 6.3% 4.9% Best annual performance under similar conditions 4.7% 3.1% 4.9% 3.5% 6.9% 5.3%

Accordingly, we have concluded that the an appropriately conservative estimate the potential heat rate improvements (and accompanying reductions in CO2 emission rates) that EGUs can achieve on average through best practices and equipment upgrades is a 4.3-percent improvement in the Eastern Interconnection, a 2.1-percent improvement in the Western Interconnection and a 2.3-percent improvement in the Texas Interconnection. The decision to use these values as the building block 1 potential in each region is based on the weight of evidence that these are conservative values; for each region, each of the three analytical approaches in our methodology supports our determination that the heat rate improvement value we selected is achievable. Taken individually, each approach provides an independently reasonable estimate of the potential for heat rate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 553 of 1275 improvement. Furthermore, these approaches are conservative on even an individual basis because they do not account for the full extent of heat rate improvements available through equipment upgrades. While some EGUs may not have achieved significant heat rate improvement in the past and EGU owners may feel they face challenges in the future, our methodology as a whole indicates that coal-fired EGUs on average can at minimum achieve the percentage heat rate improvement selected for their region through application of best practices and some of the available equipment upgrades. A more detailed discussion of the EPA’s analysis in determining the heat rate improvement potential for existing coal-fired EGUs may be found in the GHG Mitigation Measures TSD for the CPP Final Rule. 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; 478 only that these heat

478 Examples of the many types of best practices and equipment upgrades available to coal-fired EGUs include air heater baskets; air heater seals; automate steam system drains; heat rate optimization software; coal drying systems; combustion/optimization monitoring system; condenser cleaning system; condenser retubing; fan and pump variable frequency drives; steam seal and path upgrades; turbine internals replacement; turbine steam seal upgrades; intelligent sootblowing system software; the adoption and training of O&M staff on heat rate improvement procedures; alignment of the cycle by isolating as much as possible of the high-energy fluid leakage from the steam cycle; boiler chemical cleaning; cleaning*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 554 of 1275 rate improvements are achievable in the regions through a

combination of these methods. As discussed in section V.C.3 below, we believe that a single heat rate improvement goal for each region incorporating both best practices and upgrades,based on the 11 years of hourly heat rate data for 884 coalfired EGUs available to the EPA, is a reasonable approach that is supported by our analysis, and is particularly conservative given that it does not account for the full range of heat rate improvements achievable through equipment upgrades. 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

air preheater coils; production cost optimization programs that benchmark plant thermal performance using historical plant data along with an on-site performance appraisal to identify potential areas for improved performance; remote monitoring centers with thermal performance software for monitoring heat rate; repairing boiler air in-leakage; high pressure feedwater pump overhaul; repairing flue gas desulfurization systems; repairing steam and water leaks; replacing feed pump turbine steam seals; and sliding pressure operation to reduce turbine throttling losses. These and additional heat rate improvement measures are discussed further in the GHG Mitigation Measures TSD for the CPP Final Rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 555 of 1275 specific percentage heat rate improvement. Rather, the percentage heat rate improvement value is merely reflected in the performance rates and equivalent CO 2 emission goals provided to the states. Each state has the flexibility to develop a plan

that achieves those CO 2 performance rates or emission goals by assigning the emission standards the state considers appropriate to its affected coal-fired EGUs. Similarly, depending on the content of the applicable plan, sources may achieve their emission standards through use of any of the building block measures described in this rule or any other measures permitted under the plan. b. Changes from the proposal. 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 conducted our analysis on a regional basis and reduced the overall expected percent heat rate improvement for coal-fired EGUs to 4.3 percent in the Eastern Interconnection, 2.1 percent in the Western*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 556 of 1275 Interconnection, and 2.3 percent in the Texas Interconnection. 479 These values reflect improvements achievable through both best practices and equipment upgrades because, as described above, we also no longer include a separate estimation of the potential heat rate improvement achievable solely through equipment upgrades. We received comments on our proposed statistical methodology for determining the CO 2 emission reductions opportunities achievable by coal-fired EGUs through heat rate improvements. We have closely reviewed those comments and, for the final rule, have made refinements to our methodology, as described above and explained in more detail in the TSD. 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 thenature and extent of heat rate improvements that specific coalfired 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 changes to heat rate monitoring methods at EGUs and for the installation of new

479 Had the EPA maintained a nationwide approach to analyzing the potential reductions under building block 1, the result would have been 4.0 percent.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 557 of 1275 pollution controls that comply with other rules, as discussed below in the summary of key comments. 2. Costs of heat rate improvements By definition, any heat rate improvement made by EGUs for the purpose of reducing CO 2 emissions will also reduce the amount of fuel that EGUs consume to produce the same electricity output. The cost attributable to CO 2 emission reductions, therefore, is the net cost of achieving heat rate improvements after any savings from reduced fuel expenses. As summarized below, we estimate that, on average, the savings in fuel cost associated with the percentage heat rate improvements we identified for each region would be sufficient to cover much of the associated costs. Accordingly, the net costs of heat rate improvements associated with reducing CO 2 emissions from affected EGUs are relatively low. We recognize that this cost analysis will represent the costs for some EGUs better than others

because of differences in individual circumstances. We further recognize that reduced generation from coal-fired EGUs due to the implementation of other building block measures would tend to reduce the fuel savings associated with heat rate improvements, thereby raising the effective cost of achieving

the CO 2 emission reductions from the heat rate improvements. Nevertheless, we still expect that the majority of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 558 of 1275 investment required to capture the technical potential for CO 2 emission reductions from heat rate improvements would be offset by fuel savings, and that the net costs of implementing heat rate improvements as an approach to reducing CO 2 emissions from affected EGUs are reasonable. Even if we conservatively estimate that EGUs will largely rely on equipment upgrades rather than cheaper best practices to reduce heat rate, those reductions can generally be achieved at $100 or less per kW, or $5.81 to $11.63 per metric ton of CO 2 removed, as previously estimated in the proposal and described in detail in the TSD. 480 Depending on the balance between equipment upgrades and best practices, improving heat rate would even result in a net savings for some EGUs. Based on the analyses of technical potential and cost summarized above and in the proposal 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. 3. Response to key comments

480 These cost figures from the proposal are now particularly conservative because they include the cost of significant equipment upgrades that improve heat rate, whereas building block 1 is now largely quantified based on low- or no-cost best practices, with a smaller portion of the remainder comprised of equipment upgrades.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 559 of 1275 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, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 560 of 1275 data on the overall averages, and would thus decrease our confidence in the accuracy of the results. Furthermore, states in determining the emission limitation for individual EGUs are free to apportion reductions in a way that reflects any subcategories of their choice. For a more detailed explanation of our decision not to subcategorize for purposes of determining building block 1, see the TSD. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 561 of 1275 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 2 emissions. This rule does allow for treatment of EGUs on a case-by-case basis. States may believe that individual considerations are appropriate in some cases and, accordingly, we have purposely allowed states to make decisions about how to implement specific CO 2 reductions. Our determinations of 4.3-, 2.1- and 2.3-percent heat rate improvement for EGUs in the Eastern, Western and Texas Interconnection, respectively, are conservatively based on the lowest value identified by any of our reasonable statistical analyses. If states choose to set limits on individual sources based in part on the availability of heat rate improvements, the states are free to assess heat rate improvements on a more targeted, case-by-case basis that takes into account an EGU’s previous heat rate improvement efforts, or lack thereof. The fact that states (or EGUs complying with state requirements) can make case-by-case decisions about how to achieve goals does not contradict our

conservative estimates -- which are based on millions of hours of operating data reported to the EPA by EGUs -- of how much EGUs are capable of improving their heat rate in each region*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 562 of 1275 overall. Opportunities to improve heat rate abound for affected EGUs as a whole, as evidenced by the fact that the approaches in our statistical methodology each included a comparison of an EGU’s historical heat rate to its 2012 heat rate. Furthermore, to the extent that an affected EGU was in 2012 fully implementing every possible best practice for improving heat rate, it may still be capable of improving heat rate through equipment upgrades. 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 revised TSD. 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 TSD. These overall heat rate improvement figures do not include an*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 563 of 1275 estimated percent 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 best practices and a portion of the 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,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 564 of 1275 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 (e.g., coal type, boiler type, nameplate capacity, age, cooling water system, air pollution controls) on heat rate and heat rate variability. 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 cooling water intake points. Our*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 565 of 1275 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 lack of hourly cooling water temperature data, 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 TSD for further details about this analysis. As described further in the 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 566 of 1275 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 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 percent heat rate improvement for its region as a guide while keeping in mind the uniform performance rate. The final*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 567 of 1275 rule establishes a uniform national performance rate based on the least stringent regional performance rate calculated with the building blocks. Accordingly, affected sources in regions not setting the national level have emission reduction opportunities beyond those reflected in the applicable performance rate. For affected coal-fired EGUs in the contiguous United States, a methodology that assesses potential heat rate improvement within each interconnection reflects the regionalnature of the interconnected electricity system and the regionwide scope of opportunities available for those EGUs to access emission reduction measures through emissions trading. 481 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.

481 As described in section [xxx], affected EGUs in states and territories that are isolated from the three major interconnections lack access to the same opportunities to access the building blocks across wide regions and, accordingly, have performance rates based on data specific to that state or territory.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 568 of 1275We further note, along with some commenters, that sitespecific 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 the development of a comprehensive heat rate improvement study for each of the nearly 900 coal-fired EGUs covered by this rule on a unit-by-unit basis is likely to cost on the order of $50,000 to $100,000 each (almost $50 to $100 million total) and require three to four years to complete in total. Commenters havepointed out, and we agree, that a heat rate improvementestimating effort of that magnitude and duration is unnecessarily lengthy and expensive, and we believe would not serve the broader goal-setting purpose of this rulemaking.Rather, our methodology’s reliance on individualized, unit-byunit 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 569 of 1275 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 TSD -- incorporates expected retirements of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 570 of 1275inefficient units and generation shifts away from using coalfired 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’sdatabase because they are the only publicly available, unitspecific, 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, i.e., what the EGU is able to provide to the grid. Improvements in net heat rate alone (e.g., reducing parasitic load of on-site equipment) may be possible on many units. Therefore, our use of gross heat rate to estimate potential heat rate improvement was conservative because of the additional*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 571 of 1275 opportunities to achieve the uniform performance rate through improvements in net heat rate alone. 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. 482 The results of our statistical analysis 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 improvement potential to be the same as that indicated for the region-wide gross heat rate, when in fact it is not. In order to check our assumptions concerning gross versus net heat rate, we used the IPM Power Sector Modeling Platform (version 5.14) and National Electric Energy Data System (NEEDS) (version 5.14) to analyze the anticipated incremental heat input required to operate additional add-on controls to comply with various EPA rules, including CSAPR, MATS, effluent guidelines for EGUs, and coal combustion residuals. From this analysis, we project that between 2012 and 2025, existing coal-fired EGUs are expected to

482 See above for an explanation of gross versus net heat rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 572 of 1275 install approximately 18.6 GW of wet flue gas desulphurization (FGD), 16.6 GW of dry FGD, 24.9 GW of selective catalytic reduction (SCR), and 3.9 GW of selective noncatalytic reduction (SNCR). The resulting impact from new pollution controls on existing coal-fired EGUs’ heat rate is expected to be very small, at conservatively less than 31 Btu/kWh, or less than 0.3 percent in 2025. 483 After 2025, this estimate is particularly conservative because the EPA’s cost performance models overestimate the parasitic load from individual add-on controls for future years. Furthermore, at some EGUs these newer pollution control devices will replace existing pollution control devices. Accordingly, for these EGUs, the minimal increase in net heat rate due to power required to operate new controls will be at least partially offset by the decrease in net heat rate caused by removal of the control devices currently in place. For more information about this analysis, see the TSD. 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.

483 When considered on a regional basis, we expect these controls to impact heat rate by approximately 0.3 Btu/kWh in both the Eastern and Western Interconnections, and by less than 0.1 percent in the Texas Interconnection.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 573 of 1275 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 2 emissions. These differences depend on the characteristics of the stack gas flow where the monitoring and reference method measurements are taken, and which options under the Part 75 emission measurement rules are chosen in the application of the various flow rate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 574 of 1275 reference methods. In general, more accurate stack gas flow monitoring methodologies yield lower values that, when used to calculate emissions or heat input, may lower the heat rate values reported to the EPA. 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 TSD, our review of the data shows that a relatively small amount of the data are affected by these changes; we remain confident that the values adopted for building block 1 are conservative and reasonable estimates of the potential for heat rate improvement in each region. In many instances, changes in monitoring methodology would have the result of actually underestimating the potential for heat rate improvement at some EGUs. Furthermore, because our methodology analyzes percentage heat rate improvement, our results are unaffected by EGUs that consistently used less accurate monitoring methodologies that tend to overestimate heat rate. For these and other reasons discussed in detail in the TSD, we remain confident in our results despite the marginal differences*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 575 of 1275 attributable to monitoring methodologies in some of the heat

rate data for a subset of EGUs. 484 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 2 emissions while accommodating future changes to monitoring methodologies. Consult the TSD for a more detailed explanation. Commenters said that there is no proof that lowering the heat rate will reduce variability or that reduced variability will reduce heat rate, i.e., correlation does not prove

causation. 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-

484 Furthermore, on a fundamental level, our methodology accounts for a certain amount of any residual inexactness because we have conservatively adopted the lowest value identified by any of our reasonable approaches -- all three of which are themselves conservative because they do not account for the full extent of heat rate improvements achievable through equipment upgrades.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 576 of 1275 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 TSD. 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 improvement achievable through reducing variability -- i.e., reducing variability to achieve a more consistently low heat rate. See the more detailed discussion of the statistical procedures used for the final rule, above. In particular, the application of a “consistency factor” in the analyses performed for both the proposed and final rule demonstrates the potential results if each individual EGU operated slightly more consistently with the lower heat rates that the EGU had itself previously achieved under similar

conditions. The consequence of a reduced heat rate is, of course, a

lower rate of CO 2 emissions, which is the purpose of the BSER for building block 1. This way of thinking about reduced variability is consistent with industry’s own efforts to reduce variability,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 577 of 1275 which are aimed at securing the economic benefits of a more consistently lower overall heat rate. 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. D. Building Block 2—Generation Shifts Among Affected EGUs 1. Demonstration of Ability to Reduce CO 2 Emissions through Shifting GenerationThe ability to switch generation from higher- to loweremitting generation reflects the way EGUs are generally dispatched. 485 The standard approach to dispatching generation isthrough Security Constrained Economic Dispatch (SCED), a wellestablished practice in the electric power industry. 486 As the name indicates, SCED has two defining components: economic operation of generating facilities and ensuring that the electric system remains reliable and secure. 487 Economic dispatch

485 See Preamble, II.C.1, History of the Power sector for background to this discussion. 486 “Economic Dispatch: Concepts, Practices and Issues”, FERC Staff Presentation to the Joint Board for the Study of Economic Dispatch”, Palm Springs, California, November 13, 2005. 487 “Security Constrained Economic Dispatch: Definitions, Practices, Issues and Recommendations: A Report to Congress”, Federal Energy Regulatory Commission, July 31, 2006.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 578 of 1275 generally refers to shorter-term planning and operations from a day ahead through real time. During this period, generating units are committed – a process known as “unit commitment” where units are committed to be ready to provide generation to the system when they will be needed – and then dispatched in real time to meet the electricity demand on the system. Overall changes in the level of generation from different facilities are also planned over time periods longer than this two-day dispatch period. Over a calendar year, for example, units are planned and scheduled seasonally or monthly to ensure that sufficient capacity and energy will be available to meet expected loads in an area. Over a period of a week, units are committed to be prepared to start up or shut down to meet forecast loads, and dispatch is coordinated within this planning and unit commitment framework. This process enables system operators to respond quickly to short-term changes in demand, and also to shift generation among different generation types to match longer-term requirements and goals. 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 in any event are generally operated when*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 579 of 1275 wind and sun conditions permit rather than at operators' discretion. In contrast, fossil fuel-fired EGUs have highervariable costs and are also relatively flexible. Fossil fuelfired 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 amongvarious fossil fuel-fired units, in particular between coalfired 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 2 per MWh of electricity generated as a typical coal-fired EGU. Over the past decade or more, since at least 2000, fossil fuel-fired generation has been shifting from coal- and oil-fired EGUs to natural gas NGCC units, both as a result of construction of new NGCC units, and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 580 of 1275 also as a result of dispatch of existing 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. 488 As we demonstrate elsewhere NGCC units are capable of operating at higher annual capacity factors than they have historically, so there remains considerable opportunity for increased use of existing NGCC units to replace generation currently supplied by higher emitting coal and oil/gas steam units. The electric utility industry is thus well-positioned to address the requirements of this building block by increasing use of existing NGCC units and correspondingly decreasing use of steam units. The electric industry has been shifting generation to NGCCs in recent years and is expected to continue this shift in the future. In the reference case without 111d, EIA forecasts

40 GW of coal retirements and 53 GW of NGCC additions from 2012

to 2030. 489 An EPA review of state Integrated Resource Plans (IRPs) shows a pattern of shifting away from coal steam generation to NGCC. A review of the electric utility industry structure also shows that that utilities are able to shift generation among

488 Ventyx Electric Power Database. 489 Energy Information Administration, Annual Energy Outlook 2015 reference case, ref2015.d021915a.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 581 of 1275 existing affected sources to meet the requirements of this building block. In the first instance, many of the NGCC units are owned by the same companies or affiliates as 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 EGU owner is also the dispatch entity, as in most traditional market structures, the EGU owner will generally have operational control over the unit. In organized markets such as RTOs, the

owner can exercise a similar control over the levels of generation across units by how it offers generation from its units to the market operator. In both types of market structures, environmental conditions, such as compliance costs or limits on generation, can be factored in with fuel costs to influence the timing of when the unit is offered in the dispatch, as well as the price and generation level at which the unit is dispatched. An analysis of generation data from steam and NGCC units in 2012 shows that only 23 percent of the steam generation occurred where the entity (a company or affiliate) had no NGCC generation. Among entities with both steam and NGCC generation, an increase in NGCC generation from 2012 capacity*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 582 of 1275 factors to a capacity factor of 75 percent on a net basis would represent 33 percent of the 2012 steam generation. 490 In regions with organized electricity markets (including, but not limited to, RTOs or ISOs), 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 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. An owner of a source can also reduce the generation of an EGU by substituting generation from a lower-emitting NGCC directly. This substitution can take the form of a Power Purchase Agreement from a replacement source, an alternative available both in regions with organized wholesale electricity markets or in regions without such markets. Unused capacity from existing NGCCs can be a source of supply for reducing the level of higher-emitting EGUs. 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

490 Egrid database.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 583 of 1275used for compliance by the higher-emitting EGU. Under a ratebased standard, the emissions and generation associated with apurchase or acquisition could be averaged with the higheremitting EGU emissions and generation to reduce the combined emissions rate through the use of emission rate credits. 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, but the wide range of approaches permitted by this rule – reflecting both the characteristics of the interconnected operations of EGUs and those of CO2 itself as a global-impact pollutant –provides the needed flexibility, both within a year and across multiple years, to permit EGUs to fashion these arrangements to fit their circumstances. Under a mass-based program, the steam generators simply need to reduce their generation (or buy allowances, or co-fire or repower, or install CCS). They do not need to purchase replacement, lower-emitting electricity or the environmental attributes of that electricity. They may need to do so to fulfill any electricity supply obligations they might be under, but they do not have to do so to meet the requirements of this rule. Once the steam generators reduce their generation, the other entities in the electricity system arrange for the replacement electricity. But that replacement electricity does*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 584 of 1275 not lower the emissions from the steam generation. The reduced generation by the steam generators lowers the emissions. An EGU should also be able to meet its reduction obligations by purchasing tradable emission rate credits or mass allowances. Purchased emission rate credits would be averaged into the existing generation and emissions from the EGU to calculate a reduced emissions rate in a rate-based program. Purchased mass allowances would be added to any allowances already held to

enable the EGU to hold a sufficient number of allowances to cover emissions in a mass-based program. In each case the calculation would need to reflect the type of program and the type of credit or allowance being applied (see section VIII for more detail on how these programs operate). The approaches shown here collectively demonstrate that all steam generators, regardless of size of form of ownership, can implement building block 2 through some or all of the mechanisms

described. 2. Magnitude of Generation Shift In order to estimate the potential magnitude of the opportunity to reduce power sector CO 2 emissions through shifting generation among existing EGUs, the EPA first examined information on the design capabilities and availability of NGCC units. This examination showed that, although most NGCC units*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 585 of 1275 have historically been operated in intermediate-duty roles for economic reasons, they are technically capable of operating in base-load roles at much higher annual utilization rates. Average annual availability (that is, the percentage of annual hours when an EGU is not in a forced or maintenance outage) for NGCC units in the U.S. generally exceeds 85 percent, and can exceed 90 percent for some groups. 491

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. 492 These changes in generation patterns have been driven largely by changes over time in the

491 See, e.g., North American Electric Reliability Corp., 2008- 2012 Generating Unit Statistical Brochure—All Units Reporting, http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher Availability of Gas Turbine Combined Cycle, Power Engineering(Feb. 1, 2011), http://www.power-eng.com/articles/print/volume115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html. 492 http://www.eia.gov/todayinenergy/detail.cfm?id=6990.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 586 of 1275 relative prices of natural gas and coal. Although the relative fuel prices vary by location, as do the recent generation patterns, this trend holds across broad regions of the U.S. In the aggregate, the historical data provide ample evidence indicating that, on average, existing NGCC units can achieve and sustain utilization rates higher than their historical average

utilization rates. 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. In response to comments regarding the use of nameplate capacity in determining NGCC utilization rate, 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. 493,494 In effect, these plants were being dispatched to provide base-load power. In addition to the

493 Net summer capacity is defined as: “The maximum output, commonly expressed in megawatts (MW), that generating equipment can supply to system load, as demonstrated by a multi-hour test, at the time of summer peak demand (period of June 1 through September 30.) This output reflects a reduction in capacity due to electricity use for station service or auxiliaries.” (EIA, http://www.eia.gov/tools/glossary). 494 An annual utilization rate of 75 percent on a net summer basis is similar to the proposed rule’s finding of 70 percent utilization on a nameplate basis.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 587 of 1275 15 percent of NGCC plants that operated approximately at a 75 percent utilization rate on an annual basis, some NGCC plants operated at even higher utilization rates for shorter, but still sustained, periods of time in response to high cyclical demand. For example, on a seasonal basis, a significant number of NGCC plants have achieved utilization rates greater than 90 percent on a net summer basis; during the summer of 2012 (June through August), about 30 percent of NGCC plants operated at utilization rates of 75 percent or more across the entire season. During the spring and fall periods when electricity demand levels are typically lower, these plants were sometimes idled or operated at much lower capacity factors. Nonetheless, the data clearly demonstrate that a substantial number of existing NGCC plants have proven the ability to sustain 75 percent utilization rates for extended periods of time. We view this as strong evidence that increasing the annual average utilization rates of existing NGCC units to 75 percent on a net summer basis would be technically feasible. 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. This level is based on the 85 th percentile plant in 2012. In 2012, the 90 th percentile plant operated at*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 588 of 1275 approximately 80%, a level which EPA believes is also technically feasible on average for the existing NGCC fleet. For purposes of establishing state goals, historical (2012) electric generation data are used to apply each building block and develop each state's goal (expressed as an adjusted CO 2 emission rate in lbs per MWh). In 2012, total electric generation from existing NGCC units was X TWh. After the application of the building block 2 NGCC up to 75 percent target utilization rate in each region on a net summer basis, and including generation from NGCC units that were under construction in 2012, the total generation from these existing

sources is assumed to be X TWh. Although producing X TWh of generation from existing NGCC units is not actually required, because states may choose other abatement measures to reach the state goals, the EPA nevertheless believes that producing this quantity of generation from this set of NGCC units is feasible. As a reference point, NGCC generation increased by approximately 430 TWh (an 80 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 X percent higher than 2014 levels. This reflects a smaller ramp-up rate in NGCC generation than has been observed from 2005 to 2012. We also*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 589 of 1275 expect an increase in NGCC generation of this amount would not impair power system reliability. Increases in NGCC usage at existing EGUs that displaces generation from steam sources will not impact reliability, since the available fossil generation will not change, leaving the system with adequate dispatchable resources to continue to meet reserve margin and maintain reliability. In addition, the final rule makes specific provision to ensure that reliability can be planned and

maintained under this final rule. 495 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 needed for states to achieve the goals established by this rule. 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

495 See also Reliability discussion in the state plans section.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 590 of 1275 percentage points above their average utilization rates (which have recently been in the range of 40 to 50 percent). 496 Fleetwide combined-cycle average monthly utilization rates have reached 65 percent, 497 showing that the pipeline system can currently support these rates for an extended period. If the current pipeline and transmission systems allow these utilization rates to be achieved in peak hours and for extended periods, it is reasonable to expect that similar utilization rates should also be possible in other hours when constraints are typically less severe, and be reliably sustained for other months of the year. Furthermore, this final rule will not have a significant impact on peak demand for natural gas, including winter demand when natural gas for electricity will compete with other sector demands, since the state goals are annual requirements and increases in demand for natural gas will be during non-peak periods when NGCC capacity factors are currently

low.

496 EIA, Average utilization of the nation's natural gas combined-cycle power plant fleet is rising, Today in Energy, July 9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, Today in Energy, Jan. 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data). 497 EIA, Electric Power Monthly, February, 2014. Table 6.7.A.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 591 of 1275 The second consideration supporting our view that natural gas and electricity system infrastructure would be capable of supporting increased NGCC unit utilization rates is the flexibility of the emission guidelines. The state goals do 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. The third consideration supporting a conclusion regarding the adequacy of the infrastructure is that pipeline and transmission planners have repeatedly demonstrated the ability to methodically relieve bottlenecks and expand capacity. 498 Natural gas pipeline capacity has regularly been added in response to increased gas demand and supply, such as the addition of large amounts of new NGCC capacity from 2001 to 2003, or the delivery to market of unconventional gas supplies since 2008. These pipeline capacity increases have added significant deliverability to the natural gas pipeline network

498 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today in Energy; INGAA Foundation, Pipeline and Storage Infrastructure Requirements for a 30 Tcf Market (2004 update); INGAA Foundation, North American Midstream Infrastructure Through 2035—A Secure Energy Future Report (2011).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 592 of 1275 to meet the potential demands from increased use of existing NGCC units. Over a longer time period, much more significant pipeline expansion is possible. In previous studies, when the pipeline system was expected to face very large demands for natural gas use by electric utilities about 10 years ago, increases of up to 30 percent in total deliverability out of the pipeline system were judged to be possible by the pipeline industry. 499 There have been notable pipeline capacity expansions over the past five years, and substantial additional pipeline expansions are currently under construction. 500 Similarly, the electric transmission system is undergoing substantial expansion. 501 Further, as discussed below in Sections X and X of this preamble (on state flexibilities and state plans,

499 Pipeline and Storage Infrastructure Requirements for a 30 Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas groups confident of 30-tcf market, Oil and Gas Journal, 1999. 500 For example, between 2010 and April 2014, 118 pipeline projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) were placed in service, and between April 2014 and 2016 an additional 47 pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of pipe) are scheduled for completion. Energy Information Administration, http://www.eia.gov/naturalgas/data.cfm. 501 According to the Edison Electric Institute, member companies are planning over 170 projects through 2024, with costs totaling approximately $60.6 billion (this is only a portion of the total transmission investment anticipated). Approximately 75 percent of the reported projects (over 13,000 line miles) are high voltage (345 kV and higher). http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_ Project_lowres_bookmarked.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 593 of 1275 respectively), we believe the flexible nature of the goals provides time for infrastructure improvements to occur should they prove necessary in some locations. Finally, as discussed below in section X, the EPA is finalizing a start date two years later than at proposal, or almost seven years from the date of this final rule, and then phasing in building block 2 through the interim period. Combining these factors of currently observed average monthly NGCC utilization rates of up to 65 percent, the flexibility of the emission guidelines, the rates of historical growth, and the availability of time to address any existing infrastructure limitations, it is reasonable to conclude that the natural gas pipeline system can reliably deliver sufficient natural gas supplies, and the electric transmission system can reliably accommodate changed generation patterns, to allow NGCC utilization to increase up to an average annual utilization rate of 75 percent on a net summer basis. 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 in goal-setting to be feasible and consistent with domestic natural gas supplies. Increases in the natural gas resource base have led to fundamental changes in the outlook for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 594 of 1275 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 production has increased by 32 percent over that same timeframe (from 19.2 TCF in 2000 to 25.3 TCF in 2012). EIA's Annual Energy Outlook for 2015 projects that production will further increase to 33 TCF by 2030, as a result of increased supplies and favorable market conditions. For comparison, NGCC generation growth of X TWh (calculated in goal setting) would result in increased gas consumption of roughly X TCF for the electricity sector, which is less than EIA’s projected increase in natural gas production. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 595 of 1275 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.

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. 3. Timing of Generation Shift Some stakeholders have expressed concern that the performance rate- and goal-setting methodology — in particular, calculating the interim performance rates and goals on the basis of achieving the shift in generation assumed under building block 2 by the first year of the interim period — requires*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 596 of 1275 states to achieve such a significant portion of the required CO 2 emission reductions early in the interim period that it defeats the intended purpose of providing states flexibility in how they may achieve the required emission reductions. In particular, these stakeholders have stated that significant shifts of generation away from coal-fired generators to existing NGCC units (as calculated under building block 2) will be difficult for some states to achieve by the first year of the interim period as a result of technical, engineering, and infrastructure limitations or other considerations, may limit cost-effective options for emission reductions, and might have negative implications for reliability and/or recent investments in fossil steam technology. According to these stakeholders, these concerns existed even though the proposed rule did not require all emission reductions to be achieved in 2020, but rather provided that the interim goal could be met on an average basis for the 2020-2029 period. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 597 of 1275 to a utilization of 70 percent on a nameplate capacity basis, could be achieved by 2020, as part of building block 2 and for purposes of establishing state goals. In contrast, the EPA proposed that reductions in CO 2 emissions from fossil fuel-fired units associated with other measures, such as increased utilization of RE generating capacity and increased demand-side energy efficiency, would be achievable on a phased-in basis between 2020 and 2029, reflecting the necessary time needed for deployment (79 FR 34866). We note that the design of the guidelines makes clear that states are not required to reach their targets using precisely the levels of each building block that the EPA used to determine each state's goal. Nevertheless, some stakeholders have expressed concern that it may not be feasible to ensure significantly higher levels of utilization for existing NGCC units that might be required in order to meet the interim state goals because of the time required to improve natural gas pipeline infrastructure in some states. Stakeholders have also stated that, while some coal-fired units have recently been constructed and many have received significant capital investment (e.g., in the form of pollution control retrofits), some states' interim goals could not be achieved unless these units stop operating by 2020. According to stakeholders, this*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 598 of 1275 concern particularly applies for states that have both significant amounts of steam generation and significant amounts of existing NGCC capacity that is not currently being operated at high levels of utilization. In light of these concerns, the EPA solicited comment in the proposal on potential rationales for phasing in the potential to shift generation under building block 2 in the subsequent NODA (79 FR 64543). As described in section X of this preamble, the EPA has revised the interim compliance period to start in 2022, which in and of itself provides a meaningful response regarding the concerns expressed by commenters about the timing of building block 2’s generation shift potential. More specifically in response to the comments about building block 2 received from stakeholders, the EPA has evaluated the timing of implementation of building block 2 within the framework of BSER, and is finalizing a change to building block 2 that 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 (e.g., natural gas pipeline expansion or transmission improvements) that might be needed to support more use of existing natural gas-fired generation, and provides states with increased ability coordinate actions taken under building block 2 with actions*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 599 of 1275 taken under building block 3 (operation of new renewable capacity). Additionally, this phase-in increases the flexibility provided to states to address capital investment concerns regarding individual sources when scheduling compliance actions over the course of the interim and final periods. The phase-in schedule is 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 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 502 . We believe this is a conservative estimate of the ability of the sector to increase utilization of NGCC capacity between now and 2022, given that this increase already occurred in a single year. The second parameter is based on the average

502 US EIA Monthly Energy Review, Table 7.2b Electricity Net Generation: Electric Power Sector (2015). Available at: http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B& freq=m.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 600 of 1275 annual growth in gas-fired generation in the power sector between 1990 and 2012, or approximately 5 percent per year. 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. As discussed in Section X, 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 BSER level of shifting from fossil steam generation to NGCC generation is completed. Under this approach, building block 2 is completely phased into the performance rates of all regions by the end of the interim period. This phase-in, in addition to the flexible nature of the goals (discussed below in Sections X and X of this preamble),

ensures that the overall framework of this final rule includes sufficient flexibility, particularly with respect to timing of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 601 of 1275 and strategies for reducing emissions from the affected units, so that states can develop cost-effective strategies, and states, utilities, grid operators and others can readily respond to unexpected changes or demands on the energy system, such as severe weather, and allow for infrastructure improvements to occur should they prove necessary in some locations.

4. Cost 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 2 emissions reduction strategy, we next turn to the question of cost. The cost of the power sector CO 2 emission reductions that can be achieved through shifting generation among existing fossil fuel-fired EGUs depends on the relative variable costs of electricity production at EGUs with different degrees of carbon intensity. These variable costs are driven by the EGUs' respective fuel costs and by the efficiencies with which they can convert fuel to electricity (i.e., their heat rates). Historically, natural gas has had a higher cost per unit of energy content (e.g., MMBtu) than coal in most locations, but for NGCC units this disadvantage in fuel cost per MMBtu relative to coal-fired EGUs is typically offset in significant part, and sometimes completely, by a technological heat rate advantage.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 602 of 1275 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 2 emission reductions through generation shifting within defined areas (consistent with the application of building blocks for performance rate- and goal-setting), without consideration of the availability of emission reduction measures reflected in the other building blocks. To evaluate how EGU owners and grid operators could respond to a state plan's possible requirements, signals, or incentivesto shift generation from more carbon-intensive to less carbonintensive EGUs, the EPA analyzed a series of scenarios in which the fleet of NGCC units within each of the regions considered for quantifying BSER (i.e., the three interconnections) was directed to achieve a specified average annual utilization rate across that region on a net basis. The EPA conducted such scenarios to address average utilization targets of 70 percent, 75 percent and 80 percent on a net basis, allowing for shifting of fossil generation between existing units within the regions described above. This scenario identifies a generation pattern that would meet electricity demand at the lowest total cost, subject to all other specified operating and bulk power transfer constraints for the scenario, including the specified average

NGCC unit utilization rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 603 of 1275 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 business-as-usual scenario. For the scenario reflecting a 75 percent NGCC utilization rate on a net basis with regional fossil generation shifting, comparison to the business-as-usual case indicates that the average cost of

the CO 2 reductions achieved over the 2022-2030 period was $40 per

metric ton of CO 2 , comparable to the average cost estimated for this building block at proposal. We view these estimated costs as reasonable and therefore as supporting the use of a 75 percent net utilization rate target for purposes of quantifying the emission reductions achievable at a reasonable cost through the application of building block 2 in the BSER. We also conclude from these analyses that potential impacts to fuel prices and electricity prices from achieving the extent of fossil generation shifting estimated 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 X over the 2022-2030 period, which is well within the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 604 of 1275 range of historical natural gas price variability. 503 Projected wholesale electricity price increases over the same period were X, which similarly is well within the range of historical electric price variability. These projected impacts on prices were captured in the emission reduction costs of these scenarios already described above, which are reasonable and support use of a 75 percent NGCC utilization rate target for purposes of quantifying the emission reductions achievable through application of the BSER. 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 state goals. One reason for this is that the building block 2 phase-in reduces the average utilization rate over the interim period to less than 75 percent in all three interconnections. Additionally, the 75 percent utilization rate in the scenario exaggerates the stringency with which building block 2 is actually reflected in each of the state goals: While the goal computation procedure uses a maximum of 75 percent (before the phase-in) as a target NGCC utilization rate on a national average basis, this target is only achieved in the Eastern

503 According to EIA data, year-to-year changes in natural gas prices at Henry Hub averaged 29.9 percent over the period from 2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 605 of 1275

Interconnection. Performance rates in the Western and Texas Interconnections are not based on the full 75 percent NGCC utilization rate in those regions. Also, at least some states may be able to achieve additional emission reductions through other measures that, if less costly than generation shifting,

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’ flexibility to choose among alternative CO 2 reduction strategies that could offer lower-cost reductions, instead of relying on fossil generation shifting to the extent analyzed here. Based on the analyses summarized above, the EPA concludes that an average annual utilization rate for each region’s NGCCunits of up to 75 percent is a technically feasible, costeffective, and adequately demonstrated building block for BSER. For further information on the analysis discussed in this section, see Chapter X of the GHG Mitigation Measures TSD for

the CPP Final Rule. 5. Major Comments and Responses 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 proposed*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 606 of 1275 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 multiple comments regarding the proposed use of nameplate capacity in calculating the generation potential 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. In response, the EPA reexamined historical data on a net summer basis and found that increasing the annual average utilization rates of existing NGCC units to 75 percent on a net summer basis would be technically feasible. Consistent with this analysis, performance rate and state goal calculations in the final rule are also based on net summer generating capacity. The EPA also 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 2 emissions from flaring of methane will likely decrease under the Clean Power Plan. Furthermore, the changes in upstream methane emissions are small relative to the changes in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 607 of 1275 direct emissions from power plants. The technical details supporting this analysis can be found in the Regulatory Impact

Assessment. Commenters also express 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 RTO or ISO. These entities currently control the dispatch of their units while respecting existing all 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 does not need to control the dispatch. Commenters have further argued that the proposed rule will have the unintended consequence of requiring environmental dispatch. The EPA does not believe the proposed rule has any such consequence, because nothing in the rule requires dispatch entities to depart from current economic dispatch principles. This final rules makes that point even clearer by emphasizing*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 608 of 1275 the role of market based approaches and the use of tradable

emission rate credits and mass allowances that enable the incorporation of costs as part of the standard economic dispatch. Other comments object to the use of a single capacity factor goal on the grounds that not all units can achieve this goal of the highest performing units, and that some may be designed for cycling and so may need upgrades. The EPA disagrees with these comments. The 75 percent capacity factor establishes a regional potential for generation from existing NGCC capacity, and an individual unit requirement. The EPA has set this target to reflect the fact that a portion of NGCC units already run above that capacity factor and are generally designed to have

availabilities above that level. 504 Moreover, by encouraging higher capacity factors, the final rule should actually result in less cycling rather than more. Another concern expressed by commenters on the proposed rule was the disparity in state goals among different states. The EPA recognizes these comments and has designed the final rule to greatly reduce such disparity, by setting a single performance rate for each technology and using those performance rates as the basis for calculating state goals. As a result, the

504 See Chapter X of GHG Abatement TSD.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 609 of 1275 EPA believes these adjustments to the rule address these

comments. E. Building Block 3 — New Low- and Zero-carbon Generating Capacity

The third element of the foundation for the EPA’s BSER determination for reducing CO 2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which generation at the affected EGUs can be replaced by using an expanded amount of low- and zero-carbon electricity generating capacity, such as renewable electricity (RE), to produce replacement generation. In this section we address: the history and trends in RE development, the importance of expanding the use of RE, the adequate demonstration of this building block as a component of the BSER, changes made from the proposal, key comments, the method by which RE target generation levels are quantified, the magnitude and timing of increases in RE generation associated with this building block, and the reasonableness of costs

associated with those increases. 1. History of RE Development RE generating technologies are a well-established part of the U.S. power sector. These technologies generate electricity from renewable resources, such as wind, solar and water. While RE has been used to generate electricity for over a century, the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 610 of 1275 push to commercialize RE more broadly began in the 1970s. 505 Following a series of energy crises, new federal organizations and initiatives were established to coordinate energy policy and promote energy self-sufficiency and security, including solar energy legislation, the Public Utility Regulatory Policies Act of 1978 (PURPA) and the 1980 Energy Security Act. 506 PURPA was a key step in stimulating RE development. By requiring utilities to purchase generation from qualifying facilities (i.e., certain CHP and RE generators) at avoided costs, PURPA opened electricity markets to more RE generation and gave rise to non-utility generators that were willing to try new RE technologies. 507 Since 1992, federal tax policy has provided important financial support via tax credits for the production of RE and investments in RE. While the specific provisions for these tax credits have expired and been renewed (or extended) a number of

505 Nearly all hydroelectric capacity was built before the mid1970s. U.S. DOE. History of Hydropower. Accessed March 2015. Available at: http://energy.gov/eere/water/history-hydropower. 506 U.S. DOE Office of Management, Timeline of Events: 1971-1980. Accessed March 2015. Available at:http://energy.gov/management/office-management/operationalmanagement/history/doe-history-timeline/timeline-events-1. 507 “Restructuring or Deregulation?" Smithsonian Museum of American History. Accessed March 2015. Available at: http://americanhistory.si.edu/powering/dereg/dereg1.htm.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 611 of 1275 times, the financial support has helped drive recent growth in

RE. 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 have enforceable RPS or

similar laws. 508 These RPS requirements and federal tax creditscontinue to drive the relatively robust near-term growth of nonhydropower RE. 2. Trends in RE Development 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 (e.g.,

508 Energy Information Administration, Annual Energy Outlook 2014 with Projections to 2040, at LR-5 (2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 612 of 1275 modern wind turbines power electronics allow turbines to provide voltage and reactive power control at all times). 509,510 Use of RE continues to grow rapidly in the U.S. In 2013, electricity generated from RE technologies, including conventional hydropower, represented 13 percent of total U.S. electricity, up from 9 percent in 2005. 511 Total non-hydro RE capacity was approximately 16,000 megawatts (MW) in 1998. In 2013, total non-hydro RE capacity was five times higher with 80,000 MW. 512 In particular, there has been substantial growth in the wind and solar photovoltaic (PV) markets in the past decade. Since 2009, wind energy has tripled and solar capacity has grown twenty-fold. 513

509 IPCC, Renewable Energy Sources and Climate Change Mitigation, 2012. Accessed March 2015. Available at:http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 510 American Wind Energy Association. AWEA Comments on EPA’s Proposed Carbon Pollution Emission Guidelines for Existing Stationary Sources and Supplemental Proposed Rule. p. 107. 511 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at LR-5 (2014), P. ES-6 and Energy Information Administration, Monthly Energy Review, May 2015, Table 7.2b, Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 512 Energy Information Administration, 1990-2013 Existing Nameplate and Net Summer Capacity by Energy Source Producer Type and State (EIA-860), Available at: http://www.eia.gov/electricity/data/state/. 513 Energy Information Administration, Monthly Energy Review, May 2015, Table 7.2b. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 613 of 1275 The global market for RE is projected to grow to $460 billion per year by 2030. 514 RE growth is further spurred by the significant amount of existing natural resources that can support RE production in the United States. 515 In the Energy Information Administration’s Annual Energy Outlook 2015, RE generation grows substantially from 2013 to 2040 in the

reference case and all alternative cases. 516 In the reference case, RE generation increases by more than 70 percent from 2013 to 2040 and accounts for over one-third of new generation capacity. 517 3. Importance of Increasing Use of RE Currently, the utility power sector accounts for 40 percent of total annual energy consumption in the U.S. 518 Introducing more zero-emitting RE generation over the long-term could significantly reduce CO 2 emissions, as production of RE

514 “Global Renewable Energy Market Outlook.” Bloomberg New Energy Finance, November 16, 2011, Available at: http://bnef.com/WhitePapers/download/53. 515 Lopez et al., NREL, ‘‘U.S. Renewable Energy Technical Potentials: A GIS-Based Analysis,’’ (July 2012). 516 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at LR-5 (2014), P. 25. 517 Energy Information Administration, Annual Energy Outlook 2015 with Projections to 2040, at LR-5 (2014), P. ES-6-7. 518 U.S. Energy Information Administration Annual Energy Review, 2011. Accessed March 2015. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/flow/primary_ene rgy.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 614 of 1275 predominantly replaces fossil fuel-fired generation and thereby avoids the emissions from that replaced generation. A number of studies and recent policy developments have acknowledged RE as an important means of achieving CO 2 reductions. California cited the reduction of CO 2 emissions from electrical generations as one of the reasons for increasing its RE target from 20 percent to 33 percent by 2020 (and potentially 50 percent by 2030). 519 A recent IPCC report also concluded that RE has large potential to mitigate CO 2 emissions. 520 Increased use of RE provides numerous benefits in addition

to lower CO 2 emissions.RE typically consumes less water than fossil fuel-fired EGUs. Wind power and solar PV systems do not require the use of any water to generate electricity; water is only needed for cleaning to ensure efficient operation. In contrast, utility boilers, in particular, require large quantities of water for steam generation and cooling. 521 Increasing RE use will also continue to lower other air pollutants (e.g., fine particles, ground-level ozone, etc.),

519 California S.B. 2 (1X), 2011. Accessed March 2015. Available at : http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.pdf

. 520 IPCC, Renewable Energy Sources and Climate Change Mitigation, 2012. Accessed March 2015. Available at:http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 521 EPA, Water Resource Use. Accessed on March 2015. Availableat: http://www.epa.gov/cleanenergy/energy-and-you/affect/waterresource.html.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 615 of 1275 diversify energy supply, hedge against fossil fuel price increases and create economic development and jobs in manufacturing, installation, and other sectors of the economy. 4. Ownership of RE by Fossil Fuel-Fired EGUs The ability of affected EGUs to obtain incremental RE to

reduce CO 2 emissions is well-demonstrated, whether it is through direct ownership, bilateral contracts, or procurement of the environmental attributes associated with RE generation. 522 Consequently, the EPA believes that an increase in RE is a proven way to reduce CO 2 emissions at affected EGUs of all types

at a reasonable cost. Affected EGUs have already directly invested in RE. Of the 417 entities that owned part of at least one affected EGU under this rule, 191 also owned RE (biomass, geothermal, solar, water or wind). These 191 owners owned 84 percent of affected EGU capacity. As a whole, these entities’ share of RE capacity was equal to 21 percent of the total of their affected EGU capacity. 523 Some of the largest owners of affected EGUs also owned RE (see Table 7). Of the more than 3,000 MW of RE capacity owned by NRG Energy, Inc., solar represents over 20 percent (nearly 800

522 Refer to GHG Abatement Measures TSD for additional ownership statistics. 523 SNL Energy. Data used with permission. Accessed January 2015.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 616 of 1275 MW) and wind was almost 80 percent of the total (over 2,500 MW). Duke Energy Corporation owns 175 MW of solar and over 1,500 MW of wind. NextEra Energy, Inc.’s share of RE capacity approaches 40 percent of their total affected EGU capacity. 524 **TABLE 7. Ownership of Affected EGUs and RE Capacity.**

Ultimate Paren t C overed Units Generation (MWh) C overed Units Capacity (MW) Renewable Capacity (MW)

NRG Energy, Inc. 112,018,189 48,964 3,303 Duke Energy Corporation 155,255,056 38,446 4,917 Southern Company 138,080,958 36,328 3,317 American Electric Power Company, Inc. 143,547,594 35,526 1,158 NextEra Energy, Inc. 104,325,610 28,344 11,164 Calpine Corporation 99,589,172 24,148 1,637 Entergy Corporation 48,954,652 23,411 145 Tennessee Valley Authority 83,774,468 21,717 5,429 Berkshire Hathaway Inc. 83,558,238 18,899 6,342 FirstEnergy Corp. 72,021,222 16,175 1,372 Large vertically integrated utilities generally have multiple options for investing in RE, including building their own RE capacity or procuring RE under a long-term power purchase agreement. Municipal utilities and rural cooperatives that own generating asset portfolios, particularly generation and transmission cooperatives and larger municipal utilities, have also used RE to reduce carbon emissions. Large generation and transmission cooperatives also purchase significant quantities

524 Ibid.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 617 of 1275 of RE for their members. Federal power authorities own or contract significant amounts of RE. 525,526 The list of the ten largest electric utilities with wind power capacity on system (owner or under contract) includes vertically integrated utilities, municipal utilities, and federal power authorities. Xcel Energy and Berkshire Hathaway Energy rank number one and two with 5,736 MW and 4,992 MW of wind capacity, respectively. Basin Electric Power Cooperative had 716 MW and CPS Energy, a public utility, had 1,059 MW of wind power capacity. 527 Many affected EGUs are already planning on significant amounts of RE according to their integrated resource plans (IRPs). For instance, Dominion plans for over 800 MW of wind and solar in their 2015 to 2029 planning period. 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).

525 American Wind Energy Association. AWEA Comments on EPA’s Proposed Carbon Pollution Emission Guidelines for Existing Stationary Sources and Supplemental Proposed Rule. pp. 88-91. 526 SEIA comment pp. 98-147. 527 American Wind Energy Association. U.S. Wind Industry Annual Market Report (2014 data). Accessed April 2015. Available at http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDto ken=64560&userID=.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 618 of 1275 EPA agrees with commenters that highlighted the opportunity owners and operators of affected EGUs across the U.S. already have to procure RE. Commenters found many fossil fuel-fired EGU owners own or contract for RE and can control the dispatch mix among these sources. One commenter highlighted that 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. The commenter similarly observed that EGU owners participating in organized markets retain sufficient control to substitute fossil fuel-fired generation with RE, even when those EGU owners do not directly determine dispatch among energy sources. They offered the example of Oklahoma Gas & Electric (OG&E), which owns generation assets utilizing coal, gas-fired combined cycle and wind technology and is able to make decisions regarding the utilization of fossil fuel-fired EGUs and energy assets within the rules of the regional transmission organization (RTO). OG&E and other EGU owners, including munis*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 619 of 1275and co-ops operating in organized markets, can also make longerterm decisions about what types of capacity they choose to develop going forward. The commenter also emphasized that independent power producers (IPPs) also can and do own both RE and fossil generation. They provided the example of NRG, which 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 2 emissions from its fleet 50 percent by 2030 (from a 2014 baseline). NRG has already reduced CO 2 emissions from its fleet by 40 percent since 2005. This demonstrates that when an IPP commits to shifting its generation portfolio, it can do so at reasonable cost and without reliability impacts. The NRG example

shows that reduced utilization of fossil fuel-fired EGUs that is replaced by RE also owned by the EGU owner is adequately

demonstrated. Commenters said EGU owners can replace fossil fuel-fired generation with RE through bilateral contracts and renewable energy credit (REC) purchases. They stated that the bilateral market for RE and REC markets are well developed. There are no legal or technical obstacles to a fossil fuel-fired EGU owner*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 620 of 1275 acting as the counterparty of a bilateral contract for purchase of energy from a RE facility. Purchase of RECs tracked in a registry is not limited to utilities. Third parties, including IPPs, can purchase and retire RECs. To date, there has not been significant need for merchant generators to purchase RECs. However, there are no legal or technical obstacles that would prevent this action. 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. 5. Renewable Energy Credit Markets 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 represent the generation of one megawatt-hour (MWh) of RE and certain information or characteristics of the generation, called

attributes. 528 RECs are traded and transferred regardless of the actual energy flow. REC ownership confers the right to claim the generation attributes.

528 EPA Green Power Partnership, Renewable Energy Certificates July 2008). Available at http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 621 of 1275 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 ruled that states have created RECs in programs designed to promote increased use of RE, and that “attributes associated with the facilities are separate from, and may be sold separately from, the capacity and energy.” 529 In complying with states’ RPS requirements in 2012, 61 percent of RECs were sourced from in-state resources (65 percenton weighted average basis). When sourcing RECs from out-ofstate, RPS requirements typically restrict eligible RECs to the state’s region (e.g., ISO or neighboring states). 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. 530

529 FERC Docket No. EL03-133-000, Petition for Declaratory Order and Request for Expedited Consideration, American Ref-Fuel Company, Covanta Energy Group, Montenay Power Corporation, and Wheelabrator Technologies, Inc. June 16, 2003, Order Granting Petition for Declaratory Ruling , October 1, 2003. American RefFuel Co. et al ., 105 FERC ¶ 61,004 (2003); and Order Denying Rehearing . April 15, 2004. 107 FERC¶ 61,016 (2004). Availableonline at: http://www.ferc.gov/whats-new/comm-meet/041404/E28.pdf (accessed 11/7/2014). 530 Heeter, J. Quantifying the Level of Cross-State Renewable Energy Transactions. NREL 2015. Available at http://www.nrel.gov/docs/fy15osti/63458.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 622 of 1275 6. Quantification of Renewable Energy Generation Potential for BSER and Major Comments The methodology for quantifying RE target 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. In evaluating the proposed and alternative RE approaches, commenters observed that RPS, as the basis for setting RE target generation levels under the proposed approach, are policy instruments that states may choose to implement for a variety of reasons not related to CO 2 emission reductions. Additionally, differences across RPS policies in eligible resources, crediting mechanisms, deliverability requirements, alternative compliance payments, and other policy elements made the regional averaging of state-level RPS requirements challenging. Finally, commenters provided data demonstrating that RE resource potential can vary significantly within theregions identified under the proposed approach, producing statelevel targets that may not be aligned with the opportunity to deploy incremental RE resources at reasonable cost. In contrast, commenters argued that a methodology similar to the alternative RE approach, which is based on economic potential, represents a more technical basis for quantifying building block 3 target*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 623 of 1275 generation levels that accounts for regional differences in RE resources and power market conditions. The EPA agrees with these

comments. Within the framework of the alternative RE approach, the EPA received significant comments on the interstate nature of RE and the power system, use of total RE generation to define target generation levels, RE technologies that contribute to setting target generation levels, cost and performance estimates associated with those technologies, magnitude of the reduced cost applied to new RE capacity as an incentive to deploy, and application of a nationally uniform technical potential limiter to modeled projections of economic deployment. Based on commenter data and information, the primary adjustments the EPA made to the alternative RE approach are:

 The target generation level is 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. 531 Specifically, the target generation levels under building block

531 Consistent with the November 2014 Notice of Data Availability, the final goal setting methodology assumes replacement of affected EGU generation by incremental building block 3 generation in calculating source-specific CO 2 emission performance rates. For additional information on the goal setting methodology refer to Section VI.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 624 of 1275 3 include all generation from BSER RE technologies that commenced operation subsequent to the BSER data year of 2012.

 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), target 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.

 The BSER RE technologies used to quantify target generation levels no longer include landfill gas and concentrated solar power (CSP). Incremental landfill gas and CSP generation are no longer projected to deploy on an economic basis during the compliance period and consequently have been removed as BSER RE technologies. All other RE technologies from the proposed alternative approach – onshore wind, utility-scale solar PV, geothermal and hydropower – are maintained as part of the BSER and no new RE technologies have been added.

 Commenters observed that the cost and performance estimates the EPA relied on at proposal from the Energy Information Administration’s Annual Energy Outlook 2013 are outdated and 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. Commenters provided data from a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 625 of 1275 variety of sources to support these claims, including Lawrence Berkley National Lab, the Department of Energy (DOE) and Lazard. Consequently, cost and performance estimates for onshore wind and utility-scale solar technologies were revised to reflect the mid-case estimates from the National Renewable Energy Laboratory’s (NREL’s) 2015 Annual Technology Baseline.

 The final methodology for quantifying building block 3 target generation applies a reduced cost of building new RE capacity of $40 per metric ton CO 2 . This cost represents the avoided cost of

other actions that could be taken instead to reduce CO 2 emissions from the utility power sector and, unlike at proposal, is not derived from RE technology cost assumptions but rather results from the costs associated with building block 2. A harmonized cost-effectiveness threshold across building blocks 2 and 3 ensures that emission reduction opportunities are evaluated for inclusion in the BSER on equitable terms.

 The technical potential limiter that constrained cost-effective RE deployment under the alternative approach has been removed from the final methodology. 532 Commenters observed several issues with applying the technical potential limiter, including that

532 The technical potential limiter was a nationally uniform, technology-specific limit on cost-effective RE deployment based on the amount of 2012 generation in a state as a share of that state’s total technical potential.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 626 of 1275 this feature limits future performance to historical levels of development, does not factor in the total size of the RE resource in a given state, relies on non-exclusive resource estimates where a single area of land may contribute to the technical potential of multiple RE technologies, and is inconsistent with a regional approach to quantifying target generation levels. EPA agrees with these comments and the technical potential limiter has been eliminated. In addition to the comments described above, the EPA received significant comments on a wide variety of topics related to building block 2. Many of these comments provided helpful information and insights, and have resulted in improvements to the final rule. These comments, as well as EPA responses are available in the Response to Comment document. The final methodology for quantifying incremental RE targetgeneration levels relies on a combination of modeling and nonmodeling approaches that produce regional technology-specific

estimates. Estimates for the economic potential of new hydropower are the result of a DOE avoided cost methodology that develops regional hydropower supply curves and compares that supply potential against the revenue available to those projects through regional marginal generation prices and capacity values.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 627 of 1275 The deployment levels of hydropower are increased until total generation costs, inclusive of the reduced cost of building new RE capacity, equal avoided costs for each region. In contrast, economic potential estimates for utility-scale solar photovoltaic (PV)), onshore wind and geothermal technologies are the result of IPM modeling projections that 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 (resource quality, land use exclusions, terrain variability, distance to existing transmission, population density etc.), system constraints (interregional transmission limits, partial reserve margin credit for intermittent RE installations, minimum turndown constraints for fossil fuel-fired EGUs, short-term capital cost adders to reflect the potential added cost due to competition for scarce labor and materials etc.) and technology constraints (construction lead times, hourly generation profiles for non-dispatchable resources by season etc.). 533 Additionally, deployment of variable, non-dispatchable RE resources in IPM is limited to 20 percent of net energy for load by technology type

533 Refer to GHG Abatement Measures TSD for more detail on modeling methodology.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 628 of 1275 and 30 percent of net energy for load in total at each of IPM’s 64 U.S. sub-regions. 534 These constraints do not represent a technical feasibility limit but rather a conservative view of penetration levels that would not require significant grid integration costs. 535 To reflect the interstate nature of the power system, the economic potential identified under the avoided cost and modeling approaches is presented on a regional basis. Three power sector regions are used for this purpose – the Eastern Interconnection, Western Interconnection and Texas

Interconnection. 536 The regional economic potential in 2030 sets the final RE target generation level under building block 3. To ensure adequate opportunity to plan for and implement any necessary RE integration strategies and investments, 2030 economic potential levels are phased in over the interim compliance period in three stages – 2022 through 2024, 2025 through 2027, and 2028 through 2030. The first stage of deployment limits growth in RE target generation to annual increases consistent with the most recent

534 Regions that have already exceeded these limits are held at historical percent of net energy for load. 535 Refer to the GHG Abatement Measures TSD for additionalinformation on constraints related to deployment of nondispatchable RE. 536 Refer to Section V.A.3.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 629 of 1275 five-year deployment averages for the BSER RE technologies. The second stage limits annual target generation growth to levels consistent with the historical maximum deployment for the BSER RE technologies. The third stage increases target generation levels at a constant level from 2028 through 2030 to achieve the 2030 economic potential. 537 Regional RE target generation values for all years, representing RE generation incremental to the BSER data year of 2012, are presented below. **TABLE 8. Building Block 3 Target Generation Levels (MWh).**

Year Eastern Interconnection W estern Interconnection E l e ctric R eliability Council of Texas 2022 145,326,468 56,931,543 31,058,067 2023 167,746,931 60,443,578 37,217,478 2024 189,692,816 64,798,622 43,008,457 2025 233,278,550 76,786,908 53,643,200 2026 271,801,204 95,456,423 62,659,794 2027 309,867,354 114,669,103 71,589,727 2028 366,885,008 141,757,894 84,920,883 2029 423,280,371 169,587,110 98,133,904 2030 479,177,844 198,008,732 111,252,409

7. Cost of CO 2 Emission Reductions from Renewable Energy

Generation The EPA believes that RE generation at the levels represented in building block 3 can be achieved at reasonable costs. The DOE avoided cost methodology applies a reduced cost

537 Additional information on interim period RE target generation levels is available in the GHG Abatement Measures TSD.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 630 of 1275 of building new hydropower generating capacity of approximately $35 per metric ton. Under the modeling approach, the EPA applies a reduced cost of building new utility-scale solar PV, onshore wind and geothermal generating capacity of $40 per metric ton

CO 2 . This reduced cost is translated to $28 per MWh for inclusion in the modeling framework, under the assumption that incremental RE is replacing affected EGU generation of an approximate emissions intensity of 0.7 metric tons of CO 2 per MWh. 538 The projected total power system cost of applying this reduced cost to the EPA Base Case is $2.2 billion annually from 2022 through 2030. Total power system costs are a function of annualized capital costs, variable operating expenses, fixed operating expenses, fuel purchases and the expense associated with the benefit of providing the reduced cost to each qualifying RE build. The projected emission reductions average 165 million metric tons from 2022 through 2030. Consequently, the cost of achieving CO 2 reductions through the expansion of RE generation is $13 per metric ton on average from 2022 through 2030. 539 There are a number of reasons why the EPA believes that the cost

of CO 2 emission reductions from RE generation will be lower than

538 In the EPA Base Case, fossil fuel-fired EGUs are projected to operate in the EPA Base Case at approximately 0.72 metric tons of CO 2 per MWh in 2030. 539 Refer to the GHG Abatement Measures TSD for further analysis and IPM run results.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 631 of 1275 what is presented in this section. First, interim period target generation is, on average, more than 20 percent less than the economic potential identified by the modeling and avoided costapproaches. Second, modeling constraints that restrict nondispatchable RE to a percentage of net energy for load at each of the 64 U.S. IPM regions represents uncertainty associated with grid integration costs rather than a determination of technical infeasibility. In fact, many regions have demonstrated levels of RE penetration that exceed the constraints. Third, the total system costs presented in this section assume all incremental generation in the compliance period receives the full benefit of the cost reduction; however, the majority of cost-effective RE generation projected by IPM does not require the full $28 per MWh reduced cost to become economic. Fourth, there are a number of RE technologies not included in the BSER that may contribute to compliance with building block 3 target generation, including distributed generation technologies, offshore wind, CSP, waste-to-energy and many other technologies that are already in widespread use. 540 The EPA believes that these factors provide significant opportunities for lower-cost achievement of the building block 3 target generation levels. **VI. Source Category-Specific CO 2**  **Emission Performance Rates**

540 See Section VIII.G for a description of qualifying non-BSER RE technologies*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 632 of 1275

A. Overview In this section, the EPA sets out technology-specific CO 2 emission performance rates to guide states in development of their state plans. The emission performance rates reflect the emission rates for two generating source categories affected by the rule (fossil steam generation and gas-fired combustion turbines). 541 These final emission performance rates reflect the EPA’s quantification of the BSER based on the three building blocks described in section V above. This procedure follows a similar logic to BSER quantification at proposal, but it keeps the emission performance rates separate for fossil steam and NGCC source categories instead of immediately blending them together into a single value for all affected categories. Commenters noted that the proposed rule established standards that were based on the aggregation of units, and their reduction potential, in a state rather than providing technology-specific standards. While many commenters appreciated the flexibility this state-focused structure provided, some noted two concerns with this approach: 1) it would potentially create different

541 The only gas units currently considered “likely affected” units are turbines at NGCC units (both the gas and steam turbine). The remainder of the section will use the term “NGCC” to collectively refer to the output from both the steam and gas turbines at a NGCC unit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 633 of 1275 incentives for the same generating technology class depending on the state in which that generator was located, and 2) it deviated from the EPA’s previous interpretation of the 111(d) regulatory standards by not providing technology-specific standards of performance. In response to comments, the final rule establishes technology-specific emission performance rates that are identical across units within a source category regardless of where a unit is located within the continental

U.S. 542 These performance rates reflect the average emission rate requirement for each source category. Similar to the proposal, they are presented as adjusted average emission rates that reflect other generation components of BSER in addition to the fossil component. These performance rates must be achieved by 2030 and sustained thereafter. The interim performance rates apply over a 2022-2029 interim period and would be achieved on average through reasonable implementation of the best system of emission reduction (based on all three building blocks) described above. In other words, the interim performance rates are consistent with a reasonable deployment schedule of BSER

542 As noted later in this section, the approach for states and U.S. territories outside the continental U.S. does not rely on the emission performance rates because units in these areas do not have access to regional interconnected grids.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 634 of 1275 technology categories as they scale up to their full BSER potential by 2030. The performance rates are meant to reflect emission performance required across all affected units when averaged together and inclusive of lower-emitting BSER components. The performance rates are expressed in the form of adjusted 543 output-weighted-average CO 2 emission rates for affected EGUs. However, states are authorized to use a converted statewide rate-based or mass-based goal as discussed in the next

section. The EPA determined that the statewide rate-based and

mass-based CO 2 goals are expressions of the emission performance rates equivalent to application of the emission performance

rates to affected units within a state. 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 of the building blocks to that state would not be expected to produce

543 As described below, the emission performance rates include adjustments to incorporate the potential effects of emission reduction measures that address power sector CO 2 emissions primarily by reducing the amount of electricity produced at a state’s affected EGUs (associated with, for example, increasing the amount of new low- or zero-carbon generation rather than by reducing their CO 2 emission rates per unit of energy output produced).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 635 of 1275 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 2 Emission Performance Rate and Goal Computation TSD for Final Rule and the Greenhouse Gas Abatement Measures TSD. Specific topics addressed in the various TSDs are noted throughout the discussion below.

B. Performance Rate Requirements The EPA has developed a single performance rate requirement for existing fossil steam units in the continental U.S., and a single rate for existing gas turbines in the continental U.S., reflecting application of the BSER, based on all three building blocks described earlier, to pertinent data. The rates are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 636 of 1275 intended to represent CO 2 emission rates achievable by 2030 after a 2022-2029 interim period on an output-weighted-average basis collectively by all affected EGUs, with certain computation adjustments described below to reflect the potential to achieve mass emission reductions by avoiding fossil fuel-fired generation.

1. Final performance rate requirements The performance rates are set forth in Table 8 below, followed by a description of the computation methodology.**Table 8. Emission Performance Rates (Adjusted Output-Weighted Average Pounds of CO**  **2 Per Net MWh From All Affected Fossil Fuel**  **Fired EGUs). Subcategory Interim Rate Final Rate** 

**Fossil Fuel-Fired Electric Steam Generating Units**  1,465 1,290

**Stationary Combustion Turbines**  810 780

The performance rates are expressed as adjusted outputweighted-average emission rates for each technology. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 637 of 1275 MWhs (along with corresponding emissions) for the baseline electricity generation and CO 2 emissions from the higher-emitting affected EGUs. Under the final rule approach, regionally identified building block three potential generation replaces fossil steam and NGCC generation on a pro-rata basis corresponding to the historic mix of fossil generation in each region. However, as discussed in Section VIII, it the state decides to implement these adjustments in its state plan, the state must still demonstrate compliance with the CO 2 emissionperformance rates for affected EGUs or the equivalent statebased goals provided in section VII.

2. Interim Emission Performance Rates 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 638 of 1275 reflect the averaging of estimated emission performance rates for each year in the interim period (i.e., 2022-2029). 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 above.

C. Form of the Performance Rates

1. Rate-based standard The interim and final emission performance rates for fossil steam and NGCC units are presented in the form of adjusted output-weighted-average CO 2 emission rates that the affected fossil fuel-fired units could achieve, on average, through application of the measures comprising the BSER (or alternative control methods). Several aspects of this form of emission rate are worth noting at the outset: the use of emission rates expressed in terms of net rather than gross energy output; the use of output-weighted-average emission rates for all affected EGUs; the use of adjustments to accommodate incremental NGCC generation and renewable energy measures that reduce CO 2 emissions by reducing the quantity of fossil fuel-fired generation and associated emissions; and the adjustability of the goals based on the severability of the underlying building

blocks.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 639 of 1275

a. Rationale for a rate-based standard. First, the EPA sets an emission rate requirement for each source category by identifying the technology-specific reductions available under the building blocks. It then gives each state the choice to apply the emission performance rates directly to the affected units 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 or statewide mass-based goal are alternative implementation metrics for realizing the emission performance rates at the aggregate 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 standards that apply uniformly to technology categories nationwide, and the EPA is providing corresponding state emission rate goals and state mass goals to maximize 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 640 of 1275

b. Net vs. gross MWh. The second aspect noted above concerns the expression of the goals in terms of net energy output 544 – that is, energy output encompassing net MWh of generation measured at the point of delivery to the transmission grid rather than gross MWh of generation measured at the EGU’s generator. 545 The difference between net and gross generation is the electricity used at a plant to operate auxiliary equipment such as fans, pumps, motors, and pollution control devices. Because improvements in the efficiency of these devices represent opportunities to reduce carbon intensity at existing affected EGUs that would not be captured in measurements of emissions per gross MWh, goals are expressed in terms of net generation. As noted by commenters, EGUs already have in place the equipment necessary to collect and report hourly net generation, and we have determined that the reporting requirement would therefore not be burdensome.

c. Output-weighted performance rates for all affected EGUs. This final rule provides an expression of the BSER that stops

544 As discussed below in Section VIII on state plans, we are similarly determining that states choosing a rate-based form of emission performance level for their plans should establish a requirement for affected EGUs to report hourly net energy output. 545 For some EGUs, total net or gross energy output also includes useful thermal output, in addition to either net or gross electric energy output.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 641 of 1275 one step short of 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. 546 These two emission performance rates are the expression of the BSER

for the final rule for affected EGUs located within the

continental U.S.

The modification from a blended emission rate in the proposed rule to a technology-specific emission performance rate for affected EGU categories in the final rule was made in response to comments that technology-specific emission rates were more analogous to prior 111(d) efforts and more consistent with the statute. The EPA received significant comment suggesting a technology specific, source-specific requirement is consistent with past section 111(d) regulations. However, many

546 However, as discussed here and in the next section, in order to provide maximum flexibility to states, the EPA averages these two emission rates together for each state using their adjusted 2012 baseline generation share to arrive at a single statewide emission performance goal. The state has the option to comply with this statewide goal through a compliance pathway of its choice. This compliance pathway may or may not involve requiring its affected units to meet the emission performance rates.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 642 of 1275 commenters also supported the flexibility provided to states through a state goal metric provided at proposal. Therefore, the EPA does provide alternative statewide rate-based and mass-based compliance goals in the next section.

The EPA’s main consideration has been to ensure that the expression of the BSER reflects opportunities to manage CO 2 emissions by shifting generation among different types of affected EGUs. Both the performance rates in this final rule and the state goals at proposal rely on the adjusted emission rate metric to reflect that potential shifting. Specifically, because

CO 2 emission rates differ widely across the fleet of affected EGUs, and because transmission interconnections typically provide system operators with choices as to which EGU should be called upon to produce the next MWh of generation needed to meet demand, opportunities exist to manage utilization of highcarbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this

means that CO 2 emission reductions can be achieved by shifting generation from EGUs with higher CO 2 emission rates, such as coal-fired EGUs, to EGUs with lower CO 2 emission rates, such as NGCC units. Our analysis indicates that shifting generation among EGUs offers opportunities to achieve large amounts of CO 2 emission reductions at reasonable costs. The realization of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 643 of 1275 these opportunities can be reflected in an emission rate established in the form of an output-weighted-average emission rate where the weighting reflects the varying levels of replacement generation technologies.

d. Severability of building blocks. Section V above discusses the severability of the three building blocks upon which the CO 2 emission performance rates are based. Because the building blocks can be implemented independently of one another and the emission performance rates reflect the sum of the emission reductions from all of the building blocks, if any of the building blocks is found to be an invalid basis for the “best system of emission reduction ... adequately demonstrated,” the rates would be adjusted to reflect the emissions reductions from the remaining building blocks. As noted above, the performance rates and statewide goals that would result from any combination of the building blocks are computed and included in the CO 2 Emission Performance Rate and Goal Computation TSD for Final Rule and its appendices using the methodology described below

and elaborated on in that TSD.

D. Performance Rate-Setting Equation and Computation Procedure 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 2 Emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 644 of 1275 Performance Rate and Goal Computation TSD for Final Rule, which includes a numerical example illustrating the full procedure. The quantification of the building blocks used in the computation procedure is discussed in Section V above and in the

Greenhouse Gas Abatement Measures TSD.

1. Inventory of likely affected EGUs In order to calculate the source-category emission rates reflecting the BSER, the EPA first needed to develop a baseline inventory of likely affected EGUs in order to estimate the impact of BSER. The EPA developed an inventory of likely covered 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. This inventory does not constitute a final applicability determination, but best reflects the EPA’s estimate of units subject to the 111(d) applicability criteria as laid out in Section IV. The EPA identified a list of likely covered units at proposal comprised of approximately 3,000 EGUs. The agency took comment on this list and has made a number of updates to the inventory in response to those comments and in regards to applicability criteria changes resulting from comments. However, the inventory does not reflect a final applicability determination, and where*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 645 of 1275 a unit’s status was unclear, the EPA generally treated the unit’s status in a manner consistent with the proposal. 547 Since the final rule’s applicability includes under construction units, the EPA also identified units that had not yet commenced operation in the 2012 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. 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

547 The EPA notes that in some cases, it may not yet be possible to determine the status of an EGU as affected or not affected without additional data. There are potentially some units excluded or included in the baseline that will ultimately have a different status following an applicability determination. However, these cases are limited, and the effect of any ultimate change in any given unit’s applicability status is unlikely to yield a significant change in the BSER computation at the regional level. The EPA does not believe that discrepancies between the inventory we assume here to be affected by the rule and the ultimate applicability status of any given unit would introduce any significant bias into the calculation of these uniform-technology rates.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 646 of 1275 well as NEEDS data to identify these “under construction”

units. 548,549 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 2 Emission Performance Rate and Goal Computation TSD for Final Rule explains the prime mover, capacity, and fuel criteria used to identify the likely

affected EGUs. 550 The EPA received significant comment that units that came online during the baseline year (e.g., 2012) should be treated as under construction rather than operating units in 2012 for purposes of estimating baseline values, because their 2012 operation may be misrepresentative of anticipated future-year operation due to partial year operation in 2012. The EPA has

548 The NEEDS database was also updated to reflect the latest data and commenter input on under construction units. 549 For purposes of determining emission performance rates, the EPA classifies any unit that had begun construction prior to Jan. 8, 2014, but had not commenced operation by Dec. 31, 2011 as “under construction”. Some of these “under construction” units have commenced operation prior to signature of this final rule. 550 The baseline inventory relies on historical data and does not incorporate anticipated future retirements. Most commenters supported this treatment as they viewed those scheduled retirements (and corresponding emission reductions) as an alternative compliance flexibility based on already scheduled reductions.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 647 of 1275 made an adjustment to flag these units as having commenced operation during 2012 and treat them as under construction units, consistent with commenters’ suggestion; for BSER computational purposes, generation and emissions for these units are estimated based on a typical first full year operation for that technology class.

2. Data year In the proposed rule, the EPA considered using a historical-year data set, a projected-year data set, or a hybrid of the two 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 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 it 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 648 of 1275 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 a hybrid approach where it still largely relies on reported 2012 data as the best 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. Below, we explain why – at the nationwide level - 2012 data are preferable, more objective, and more accurate than a prior year, or an average of years, for informing the baseline. Then, we explain the adjustments that we are making to the 2012 data along with our rationale for such adjustments, in response to comments we

received. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 649 of 1275

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 13 GW of capacity that operated in 2010 and/or 2011 were retired prior to 2012. Using state-level, prior year data, either on its own, or as part of a multi-year baseline, is not as representative of the current power fleet as the 2012 data, which better reflects significant changes in power

sector infrastructure. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 650 of 1275 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 the Technical Support Documents. 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 a 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).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 651 of 1275 4) Due to the region-based nature of deriving 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 does 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 random 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 2 emissions performance can be made. Because the EPA is moving from a state approach at proposal to a regional approach for calculating the expression of the BSER in this final rule, unit-level operational variation from year to year becomes even less relevant to the calculation of regional emission performance rates (i.e., an outage in a fossil unit in one region is likely to be offset by increased generation from another fossil unit in that same region).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 652 of 1275 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 (i.e., less stringent) state goal. The EPA disagrees with this view for several reasons. First, the objective of selecting a baseline to inform BSER is to have one that best reflects the power sector and consequently the best system of emission reductions of which the power fleet is capable. Using an earlier baseline that “inflates” the starting point would undermine this objective, not serve it. Second, the EPA disagrees with the premise of this comment – that the baseline would change and building block potentials would stay the same. For instance, building block two is based on incremental generation potential (incremental generation = potential generation – actual generation). This incremental value would increase if an earlier baseline period was used that had less existing NGCC generation. 6) Some commenters pointed out that the EPA relied on multiyear historical data in allowance allocation in previous rulemakings (e.g., CAIR and/or CSAPR allocations).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 653 of 1275 However, that comparison is not relevant to the quantification of emission reduction potential under 111(d). In those previous instances, the EPA was considering typical unit-level behavior for allowance allocation purposes – not for determining the emission reduction requirements of the program. Those allowance allocation determinations were independent of and subsequent to the determination of emission reduction requirements in those 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 Hub natural gas prices averaged approximately $2.75/MMBTU in 2012, which is lower than previous years, this does not invalidate the suitability of the data year selection. The EPA’s objective in selecting a baseline is to identify potential reductions when BSER technologies are applied; year-to-year variation in market prices for natural gas does not frustrate this effort. For instance, a region may have generated only 5 MWh of NGCC generation in 2011 when gas prices were higher, and 10 MWh of NGCC*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 654 of 1275 generation in 2012 when gas prices dropped. However, this does not change the outcome of the EPA quantification of the BSER, because the BSER is based on the emission

reduction potential of the fleet. That potential (e.g., a fuller realization of the existing NGCC generation potential equivalent to 15 MWh) does not change regardless of the year used for baseline NGCC generation. Therefore, a different data year may change a baseline data point, but it would not change the ending point for quantifying the emission performance rates in these

circumstances. 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.

3. Adjustments that the EPA made to the 2012 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:*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 655 of 1275 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 it is 1) a significant portion of their generation portfolio, 2) 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. 551 Therefore, no similar adjustment was needed to account for weather patterns with these technologies. Unlike market conditions (e.g., changes in natural gas prices) that may produce different generation profiles year-to-year but that do not change the overall generating potential of the fossil fuel-fired fleet, variation in the hydrologic cycle does fundamentally change the generating potential of the fossil fuel-fired units in hydro-intensive states as they no longer have the same generating potential in an average year as they had in a “high hydro” year. The

551 While solar and wind generation may vary on an hourly or daily basis, their annual generation profiles are subject to notably less variation compared to hydropower. The EPA’s calculation of the BSER relies on annual generation data, not on hourly or daily generation data.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 656 of 1275

CO 2 Emission Performance Rate and Goal Computation TSD for CPP Final Rule provides analysis and explains the adjustment that the EPA made to the state-level 2012 data for Alaska, Idaho, Maine, Montana, Oregon, South Dakota, and Washington to better reflect fossil generation in an average year over a 1990-2012 baseline. The EPA agrees with commenters that using a 2010-2012 baseline would not address the concern as 2011 was also an outlier year relative to historical snow-pack and hydro generation. 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 regional average performance rates reflecting BSER purposes. 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 a state if it chooses to use a rate-based or mass-based statewide goal. Even though the EPA is calculating performance rates that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 657 of 1275 it believes are not affected by this type of unit-level variation, it still evaluated the possible impacts it may have when reconstituting state goals in the next section. The EPA examined units nationwide with 2012 outages to determine where unit-level outages 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) significantly impacted its output relative to preceding and subsequent years, and 2) significantly impacted its state’s goal was the Sherco unit 3 in Minnesota. The EPA therefore adjusted this unit’s 2012 fossil steam generation upwards (and made a corresponding adjustment to lower NGCC generation assumed to occur in Minnesota in the adjusted baseline data) 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 658 of 1275 likely over-represented as it is operating more than it otherwise would when the second unit commences operation. Therefore, the resulting annual generation level 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 represent an average annual operating level for that type of unit, which resulted in increased baseline emissions and generation assumed for those units beyond their reported partial-yearoperations in 2012. Conceptually, the assumption of fullyear 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 determine the state location of such units. As a result, this data adjustment marginally*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 659 of 1275 inflates the total generation and emissions in the 2012 baseline beyond 2012 reported levels. 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 to the baseline to address some of the relevant concerns raised by commenters.

4. Equation This section describes the equation used to determine the emission performance rates for fossil steam and NGCC units. More detailed information regarding rate computation, including example calculations, can be found in the CO 2 Emission Performance Rate and Goal Computation TSD for Final Rule, which is available in the docket for this action. The following paragraphs summarize the steps taken to adjust baseline data to reflect the building block potential and derive performance rates. The next section explains how these nationwide performance rates are reconstituted into a statewide goal metric similar to proposal if a state desires to use a statewide goal as a mechanism for demonstrating compliance at the aggregate state level in a state plan instead of applying the emission performance rates to its affected EGUs. The EPA has translated these technology-specific emission rates into statewide goals that states may use to demonstrate aggregate compliance in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 660 of 1275 section VII of the preamble and the CO 2 Emission Performance Rate and Goal Computation TSD for Final Rule. Step one (compilation of baseline data). On a unit-level basis, the EPA obtained total annual quantities of CO 2 emissions, net generation (MWh), and capacity (MW) from reported 2012 data for all affected EGUs that had commenced operation prior to

2012. 552 The EPA made limited changes to the historical unitlevel data based on comments received at proposal. For each state and region, the agency aggregated the 2012 operating datafor all coal-fired steam EGUs as one group, all oil- and gasfired steam EGUs as a second group, and all NGCC units as a third group. The EPA adjusted these state values upwards in a limited number of instances to reflect the hydro and unit outage

552 EGUs whose capacity or fossil fuel combustion were insufficient to qualify them as “likely affected” EGUs were not included in the goal computations. Most simple cycle combustion turbines were excluded on this basis at proposal, and all simple cycle CTs were excluded at final reflecting changes to the applicability language. IGCC’s were designated as “other” generation at proposal, but they are grouped with coal units for the final rule. Useful thermal output (UTO) was also translated to a MWh equivalent and included in state goals at proposal, resulting in more stringent rates for states with more cogeneration sources, but UTO is not included in this final rule emission performance rate or state goal calculations as a result of comments regarding potentially adverse impacts on cogeneration units. As described in the state plan section of the preamble, units may still quantify and convert UTO (i.e., taking credit for waste heat capture) when demonstrating compliance. See the applicability criteria described in Section IV.C above.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 661 of 1275

concerns raised in comments and described above. Per the adjustments discussed above, the EPA first only aggregated the reported data for units that commenced operation prior to 2012. For those “likely” affected units that commenced operation during 2012, the EPA treated that capacity consistent with its

framework for “under construction” affected units. For the “under construction” units (i.e., those under construction prior to January 8, 2014 but which had not commenced operation by December 31, 2011), the EPA estimated their generation and emissions using their capacity. The EPA assumed a 55 percent capacity factor for under construction NGCC units and a 60 percent capacity factor for under construction fossil steam units, which are consistent with the values and methodology the EPA proposed for under construction units. These values are based on the average capacity factors for units in these technology classes coming online in the 2007-2011 time frame. Using these capacity factors along with the capacity for the units, the EPA estimated an annual baseline generation value for these units. The agency then estimated annual baseline CO 2 emissions for these under construction units using the average emission rate of generating units of the same technology in the

state where the under construction unit is located. Where no generators of the same technology existed in a given state, the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 662 of 1275 EPA used the national baseline average for that technology. This is similar to the adjustment made at proposal, with the main difference being units that commenced operation in 2012 are now also treated as “under construction” for baseline data purposes

in the final rule. 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 to derive an adjusted historic baseline total for each state and region. 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 2012 data to the state level, the final rule further aggregates 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 under a regional structure. The basis for the regions are defined and discussed in Section V.A.3). Step three (presentation of source category baseline emission rates). As discussed in the beginning of this section,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 663 of 1275 the EPA took a technology-specific approach to setting standards. 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 applies the building blocks at the regional level maintaining a separate fossil steam rate and a NGCC rate for each region. The starting point for calculating the technology-specific emission performance rates is the adjusted baseline regional emission rate and generation value for fossil steam and NGCC separately. Step four (application of building block one). The total CO 2 emissions amount for the coal-fired steam EGU group in each region was reduced by 2.1, 2.3, and 4.3 percent in the Western, Texas, and Eastern Interconnections respectively, while the coal generation level is held constant, reflecting the EPA’s assessment of the average opportunities in each region to reduce

CO 2 emission rates across the existing fleet of coal-fired steam EGUs through heat rate improvements that are technically achievable at a reasonable cost. The EPA then averages together the region’s baseline oil- and natural gas-fired steam rate with its building block 1 adjusted coal steam rate to get a fossil steam rate post building block 1. 553

553 Building block 1 analysis acknowledges some variation in heat rate improvement potential at different units. The*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 664 of 1275 Step five (application of building block three). At proposal, the EPA incorporated incremental RE MWhs 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 three in a manner more analogous to building block two treatment where the MWhs identified for the building block replace baseline fossil MWhs levels (and corresponding emissions) on a one-to-one basis. The EPA is adopting this replacement methodology for building block three in the final rule consistent with comments noting that such a computational procedure better reflects the reduction potential of that building block. In this revised equation, part of building block three incremental RE potential and all of building block two incremental NGCC potential are ultimately applied to replace higher-emitting fossil steam generation and emissions. Because incremental RE potential is lower emitting than building block two incremental NGCC potential, building block three’s replacement impact is calculated first when determining the impact on technology rates for each affected fossil-fuel category. Calculating building block three replacement impacts

implementation of this building block simply reflects a heat rate improvement on average across a region’s coal fleet, not necessarily a heat rate improvement at every unit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 665 of 1275 first is also consistent with comments the EPA received noting that this step is necessary to ensure that the EPA can subsequently calculate the full potential of building block 2 potential to replace higher-emitting fossil steam. First, building block three replacement potential is identified for each region to arrive at a total amount of incremental zero-emitting generation hours available to replace fossil generation in the region. Next, the incremental zero emitting generation hours are assumed to replace generation and

associated emissions from each of the fossil steam and NGCC fleets in the region on a pro-rata basis in the following manner. The EPA determines the percent of fossil steam generation and the percent of NGCC generation of total affected fossil generation in each region’s baseline. It then assigns those percentages of the incremental zero-emitting MWhs to each of those technology source categories. 554 The incremental zeroemitting generation assigned to that technology replaces the respective fossil generation from that technology’s baseline value. The numerator (emissions) is also effectively reduced at

554 For example, if 100 MWh of incremental zero emitting generation is available in a given region and that region had 70 percent of its affected fossil generation coming from fossil steam units historically and 30 percent from NGCC units – then 70 MWhs of the incremental zero-emitting generation are assumed to replace baseline fossil steam generation and 30 MWhs are assumed to replace baseline NGCC generation.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 666 of 1275 this stage by the amount of average CO 2 emissions associated with the replaced fossil generation. Step six (application of building block two). If the remaining generation level for the NGCC fleet in a region, taking into account the previous steps replacement of NGCC generation, is less than 75 percent of the fleet’s potential summertime generating capacity (75 percent capacity factor), then the NGCC generation in the region is assumed to increase to levels equal to the lesser of 1) its potential at 75 percent capacity factor or 2) a generation level above which there is no longer fossil steam generation within the same region to replace. In other words, the regional NGCC capacity factor is only assumed to reach 75 percent if there is higher-emitting fossil steam generation that it could replace after step five. The incremental NGCC generation replaces fossil steam generation in the region on a one-for-one basis. This replacement reduces the amount of fossil steam generation in the fossil steam rate

denominator as well as the amount of fossil steam emissions in

the numerator. 555 As explained in step seven, when determining the final fossil steam rate, this incremental NGCC generation and

555 For purposes of determining the emission performance rates for fossil steam, incremental NGCC generation is defined as the final adjusted NGCC generation level minus the baseline level.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 667 of 1275 corresponding emissions are assigned to the fossil steam rate denominator and numerator respectively in a manner analogous to building block three. That is, the incremental NGCC generation that is replacing fossil steam generation is included in the

fossil steam denominator and the incremental emissions are

included in the numerator. 556 Step seven (arriving at the adjusted technology-specific rates for the region). In step four, the EPA calculated a regional fossil steam emission rate that reflected the building block 1 heat rate improvement. In steps five and six, it calculated an amount of remaining fossil steam generation and NGCC generation after building blocks two and three were applied. Step seven quantifies the 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 reflecting the implementation of all three building blocks.

556 Inclusion of the generation and emissions from incremental NGCC in the fossil steam rate is necessary to reflect the emission reductions associated with building block two. An unadjusted fossil steam rate on its own would not reflect any change as generation and emissions from replaced fossil steam would decrease proportionally when building block two is applied.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 668 of 1275 For the numerator of the fossil steam rate, the EPA multiplies the remaining fossil steam generation (post Step six) by the fossil steam rate reflecting the heat rate improvement from building block 1 (Step four). It then adds in the emissions associated with incremental NGCC generation from building block 2 (step six) by multiplying the incremental NGCC generation (delta between the baseline NGCC generation level and post step six NGCC generation) by the baseline NGCC rate for that region.

This constitutes the numerator of the fossil steam emission

rate. For the fossil steam denominator, the EPA adds the remaining fossil steam generation (post step six), the incremental NGCC generation, and the amount of zero emitting building block three MWhs assigned to replace fossil steam generation in the region (step five). Dividing the fossil steam

numerator described above into this fossil steam denominator results in a regional adjusted fossil steam rate reflecting the three building blocks. For the NGCC uniform technology rate, the EPA calculates a numerator in a similar manner. First, it takes the remaining NGCC generation (post step six) and multiplies it by the regional baseline NGCC rate to calculate the total emissions in the numerator. For the denominator, the EPA added the remaining*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 669 of 1275 NGCC generation (post step six) to the amount of zero-emitting building block three generation assigned to that technology in step five. Dividing the emissions into this total generation value (inclusive of the RE generation assigned to replace NGCC) provides a regional adjusted NGCC rate. Step eight (determining the nationwide technology-specific emission performance rate). Following step seven, the resulting adjusted fossil steam rates and NGCC rates for each region are evaluated. The highest (least stringent) emission rate for each technology category is identified among the three regions. This becomes the nationwide emission performance rate for that technology class. Finally, the EPA repeats steps four through eight for each year 2022-2030. The resulting annual rates vary because the amount of building block two and three potential in each year varies. The rates for years 2022-2029 are averaged together to calculate an interim rate, and the 2030 value becomes the final emission performance rate for that year forward. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 670 of 1275 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 trendedtowards, and is expected to continue to trend towards, loweremitting generation sources that will make reductions more readily available.

The CO 2 emission performance rates described in Table 8 above are relevant for the continental U.S. jurisdictions. Affected EGUs in Alaska, Hawaii, Guam, and Puerto Rico are not*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 671 of 1275 subject to these rates. Because the continental U.S. (CONUS) BSER relies on a region-wide determination of potential reductions, the non-continental United States jurisdictions with affected EGUs are not subject to this regional BSER framework. For these non-CONUS jurisdictions, the EPA developed a blended emission rate similar to proposal (but incorporating updated building block assumptions) and described in the technical support document entitled “CO 2 Emission Performance Rate and Goal Computation TSD for Final Rule,” which is available in the

docket.

**VII. Statewide CO 2**  **Emission Performance Goals**

A. Overview In section VI of this preamble, the EPA provides the methodology for computing source category-specific CO 2 emission performance rates, based on the BSER. In the June 2014 proposal, the EPA proposed a set of state-specific emission rate-based CO 2 goals (in lbs of CO 2 per MWh of electricity generated). In addition, the EPA issued emission rate-based CO 2 goals for areas of Indian country and U.S. territories with affected EGUs in a supplemental proposal on November 4, 2014. To provide flexibility to states, territories, tribes and implementing authorities, the proposals authorized each implementing authority to translate the form of the goal to a mass-based form*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 672 of 1275 (i.e., goals expressed in terms of total tons of CO 2 per year from affected EGUs), as long as the translated goal achieves the equivalent in stringency. Upon issuance of the proposed rule,

the EPA continued the extensive outreach effort to stakeholders and members of the public that the EPA had engaged in for many months preceding the proposal. We also issued a notice (79 FR67406) and technical support document (Docket ID no.: EPA-HQOAR-2013-0602-22187) to further clarify potential methods for the translation to a mass-based equivalent. The outreach provided opportunities for all jurisdictions with affected EGUs – both individually and in regional groups – as well as numerous industry groups and non-governmental organizations, to meet with the EPA and ask clarifying questions about, and give initial reactions to, the proposed components, requirements and timing of the rulemaking. As a result of the outreach and notice, the

EPA received informed substantive comments for the EPA to

consider for the final rule. Numerous commenters encouraged the EPA to allow states the maximum possible degree of flexibility in developing plans for their affected EGUs, whether a mass-based or rate-based CO 2 goal is chosen. States and other stakeholders supported the option to translate rate-based goals to mass-based goals in state plans and requested a simple and transparent method for determining*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 673 of 1275

mass-based statewide CO 2 goals that are equivalent to statewide

rate-based CO 2 goals. We received substantive comments on the potential methodologies for the translation of rate-based goals to mass-based goals. Several commenters requested that the EPA provide the translation to a statewide mass-based goals directly while others requested flexibility to translate to mass using avariety of methodologies and tools. The EPA is providing massbased statewide goals in this final rule in place of having states determine the mass values themselves. Using the comments received, the EPA is providing a straightforward and translation methodology from the CO 2 emission performance rates to yield

statewide rate-based and mass-based CO 2 emission performance goals; section VIII below discusses mechanisms for states to plan for and demonstrate achievement of the statewide CO 2 emission performance goals. The EPA is aggregating the performance rates discussed in

section VI into statewide CO 2 emission performance goals for each state to facilitate states’ efforts to formulate compliance plans encompassing maximum flexibilities. This statewide goal is not a compliance requirement, but rather an option that the state may choose to use to demonstrate that its affected fleet is complying with the technology-specific emission performance rates on average if a state chooses not to apply the performance*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 674 of 1275 rates to its affected EGUs directly. As discussed further in section VIII on state plans, the states, in turn, are charged with setting specific emission standards for the EGUs in their respective jurisdictions such that the EGUs operating under those standards together satisfy the requirements of the final emission guidelines as expressed by the emission performance rates or statewide emission performance goals.

B. Reconstituting Statewide CO 2 Emission Performance Goals from the Source Category-Specific Emission Performance Rates In order to provide states flexibility for planning purposes, the EPA is providing a state-specific averaging of the technology-specific emission performance rates to determine a statewide goal similar to the state goal metric issued at proposal. While the emission performance rates reflect the standards of performance based on the BSER, the statewide goals reflect one approach through which states may choose to adopt and implement those standards.

The EPA derived the statewide rate-based CO 2 emission performance goals by multiplying the fossil steam emission performance rate by the baseline fossil steam generation in a state and multiplying the NGCC performance rate by the baseline NGCC generation in a state. The resulting emissions for fossil steam and NGCC are then added together for each state. This*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 675 of 1275 emission total is divided into that state’s baseline generationvalues from affected units in order to develop a state’s ratebased CO 2 emission performance goal for 2030. This blended rate reflects the aggregate emission rate a state may expect to achieve when its fleet is meeting its technology-specific emission performance rates. This step is repeated for years 2022-2029 using the emission performance rates calculated for each of those years in the previous section. The resulting state emission rates for each year 2022-2029 are then averaged together to determine the state’s interim rate-based emission performance goal. This results in interim and final statewide goal values unique to

each state’s historical blend of fossil steam and NGCC generation. The EPA also 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 three and two year increments are not regulatory guidelines or equivalents for interim goals, but rather illustrative of a type of gradual reduction compliance strategy that states may use to reach their interim and final statewide goals.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 676 of 1275 The EPA is providing equivalent mass-based statewide CO 2 emission performance goals for each state, which are provided

below. The mass-based statewide CO 2 emission performance goals are based on the tonnage totals from the numerator of the

statewide rate-based CO 2 emission performance goals. These mass levels are then adjusted to account for the ability of affected EGUs to increase utilization under rate-based compliance by engaging in emission reduction strategies that are in excess of what is necessary to demonstrate compliance if affected EGUs choose to replace their own generation. Due to the nature of the emission performance rate methodology, which selects the highest regional value for each source category as the CO 2 emission performance rate, there are cost-effective emission reduction opportunities originally quantified under building blocks 2 and 3 that were not ultimately captured in the emission performance rates. The EPA recognizes that these cost-effective opportunities are available to affected EGUs in a rate-based compliance setting as a means of increasing utilization while maintaining the relevant emission performance rate. To afford affected EGUs similar compliance flexibility under mass-based compliance, the EPA has translated these excess emission reduction opportunities (which were quantified at the regional level) to a tonnage basis and then incorporated those additional*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 677 of 1275 tons into each state’s mass-based goal on the basis of that state’s share of 2012 affected EGU generation. 557 The EPA notes that it is the emission performance rates in section VI that constitute the application of BSER to the affected EGUs and serves as the chief regulatory requirement of this rulemaking. The statewide CO 2 emission performance goals provided here are metrics that states may choose to adopt when demonstrating compliance at the state level, and states may consider these goals when determining how to set unit-level compliance requirements. The EPA believes that the regional nature of determining the emission performance rates encompasses a large population size and makes it robust against unit-level variation and unit-level inventory discrepancies. The EPA does acknowledge that state-level rate-based goals or mass-based goals may be sensitive to inventory changes within a state’s fleet. That is, the EPA used a representative baseline that aggregated data for “likely affected” units. However, if subsequent applicability review or formal applicability determinations change the status of these units as of 2012 in regards to their inclusion or exclusion in the state’s

557 For more detail on the translation methodology, please refer to the technical support document, CO 2 Emission Performance Rate and Goal Computation TSD for Final Rule, which is available in the docket.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 678 of 1275 inventory, the EPA will consider allowing states, via State Plan submittal, to adjust their statewide rate or mass goal by up to 1% if such a change is necessary. This adjustment flexibility provision is based on comments received at proposal. For example, some stakeholders noted that the affected status of particular units was unclear. The EPA recognizes that all the necessary data to determine the affected status of some units may not be available at this time. Asstated in the previous section, the EPA does not believe unitlevel variation or inclusion/exclusion disparities between baseline inventory and affected units will impact the regionally determined emission performance rates discussed in the previous section. However, variations in baseline data or inventory may have an impact on the state-level rate-based or mass-based goals provided in this section. Therefore, the EPA is allowing the flexibility for states to demonstrate the need for this type of adjustment under the justifications above and utilize an adjusted value for compliance purposes when submitting its state plan. As described in the previous section, the non-continental United States (non-CONUS) jurisdictions with affected sources (Alaska, Hawaii, Guam, and Puerto Rico) required a different Best System of Emission Reduction framework as the regional*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 679 of 1275 nature of deriving emission performance rates was not appropriate for their more isolated systems. Therefore, the EPA determined bottom-up state goals for these non-CONUS jurisdictions based on the same building blocks used for the continental United States, but without the regional framework component. It then assigned the non-CONUS areas the less stringent of their state/jurisdictional specific bottom-up rateor the rate resulting from applying the continental technologyspecific emission rates into a non-CONUS jurisdictional goal based on that jurisdictions historic mix of fossil steam and NGCC generation. This “lesser of” approach is consistent with limiting the BSER so that no region or jurisdiction has to do more than the region with the least reduction potential.

**Table 9. Statewide 558**  **Rate-Based CO 2**  **Emission Performance Goals (Adjusted Output-Weighted-Average Pounds of CO**  **2 Per Net MWh From**  **All Affected Fossil Fuel-Fired EGUs)**

State Interim Goal - Step 1 Interim Goal - Step 2 I nterim Goal - Step 3 Interim Goal Final Goal Alabama Alaska Arkansas Arizona* California Colorado Connecticut Delaware

558 The EPA has not developed statewide rate-based or mass-based CO 2 emission performance goals for Vermont and the District of Columbia because current information indicates those jurisdictions have no affected EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 680 of 1275

Florida Lands of the Fort Mojave Tribe Georgia Guam Hawaii Iowa Idaho Illinois Indiana Kansas Kentucky Louisiana Massachusetts Maryland Maine Michigan Minnesota Missouri Mississippi Montana Lands of the Navajo Nation North Carolina North Dakota Nebraska New Hampshire New Jersey New Mexico* Nevada New York Ohio Oklahoma Oregon Pennsylvania Puerto Rico Rhode Island South Carolina South Dakota*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 681 of 1275

Tennessee Texas Lands of the Ute Tribe of the Uintah and Ouray Reservation Utah* Virginia Washington Wisconsin West Virginia Wyoming * Excludes EGUs located in Indian country within the state.

**Table 10. Statewide Mass-Based CO 2**  **Emission Performance Goals (Adjusted Output-Weighted-Average Tons of CO**  **2 From All Affected**  **Fossil Fuel-Fired EGUs)**

State Interim

Goal Final Goal

Alabama

Alaska

Arizona*

Arkansas

California

Colorado

Connecticut

Delaware

Florida Georgia

Guam*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 682 of 1275

Hawaii

Idaho

Illinois

Indiana

Iowa

Kansas Kentucky

Lands of the Fort Mojave Tribe Lands of the Navajo Nation

Lands of the Ute Tribe of

the Uintah and Ouray Reservation

Louisiana

Maine Maryland

Massachusetts Michigan

Minnesota Mississippi

Missouri

Montana

Nebraska

Nevada*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 683 of 1275 New Hampshire New Jersey

New Mexico *

New York

North

Carolina

North Dakota

Ohio

Oklahoma

Oregon Pennsylvania

Rhode Island

South

Carolina

South Dakota

Tennessee

Texas

Utah * Virginia Washington West Virginia

Wisconsin

Wyoming*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 684 of 1275 * Excludes EGUs located in Indian country within the state.

**VIII. State Plans**

A. Overview After the EPA establishes the emission guidelines, each

state 559 shall then develop, adopt and submit a state plan under CAA section 111(d). Each state’s obligation under section 111(d) and under these guidelines is to establish a standard of performance for the affected EGUs in its jurisdiction in order to implement the BSER. That standard of performance may expressly incorporate the CO 2 emission performance rates the EPA has set forth in these guidelines to express the BSER, or, as an alternative, the state may establish standards of performance at different levels for different EGUs. As a second alternative, the state may adopt measures apart from or in addition to standards of performance for its affected EGUs. These guidelines

include rate-based and mass-based CO 2 emission goals for each state that represent the equivalent in aggregate of the CO 2 emission performance rates applied to the affected EGUs in each state; states that adopt either of the two alternative approaches – differential standards of performance among their

559 In this section, 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 eligible to develop and implement a CAA section 111(d) plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 685 of 1275 affected EGUs or “state measures” - must demonstrate that, in the aggregate, the differential standards of performance and/or measures they adopt will result in their affected EGUs meeting in the aggregate either the states’ respective rate-based CO 2 emission goals or mass-based CO 2 emission goals. The EPA believes that it is appropriate to allow states this significant flexibility in both the timing and location of emission

reductions because CO 2 is a global pollutant, and where and when the reductions occur is not as significant to the environmental outcome as compared to many other conventional pollutants. Each state must decide whether to adopt a plan to meet the

CO 2 emission performance rates for affected EGUs – either as emission standards for each EGU reflecting the CO 2 emission performance rates that represent BSER or as emission standards differentiated among its affected EGUs, or adopt and implement, in the rate-based metric or in the mass-based metric, the CO 2 emission goals set forth by the EPA for the state. As already stated, the EPA is establishing goals for each state in order to ensure both that states and affected EGUs enjoy the maximum flexibility and latitude in meeting the requirements of the emission guidelines and that the BSER is fully implemented by each state. For its plan, a state will be able to choose to either impose federally enforceable emission standards that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 686 of 1275 fully meet the emission guidelines directly on affected EGUs (the “emission standards” approach) or use a “state measures" approach, which would comprise, at least in part, measures implemented by the state that are not included as federally enforceable components of the plan, with a backstop of federally enforceable standards on affected EGUs that fully meet the emission guidelines and that would be triggered if the state measures fail to result in the affected EGUs achieving on schedule the required emissions reductions. In developing the plan, the state rulemaking process must meet the minimum public participation requirements of these guidelines, including a public hearing and meaningful engagement with all members of the public, including affected communities. Within the time period specified in the emission guidelines (from as early as August 31, 2016, to as late as August 31, 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. During and following implementation of its plan, each state must demonstrate to the EPA that its affected EGUs are meeting the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 687 of 1275 interim and final performance requirements included in this final rule through monitoring and reporting requirements.

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. 560 This section is organized as follows. First, we discuss the state plan performance periods. 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 2 emission performance rates or state CO 2 emission goals for affected EGUs, and the consequences if they are not met. Sixth,

we discuss several additional considerations for states in developing and implementing plans, including: accounting for emission reduction measures in state plans; treatment of interstate effects; requirements for rate-based emission trading approaches; evaluation, measurement, and verification (EM&V)

560 See 40 CFR 49.1 to 49.11.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 688 of 1275 criteria for RE and demand-side EE resources used to adjust a CO 2 rate; consideration of a facility’s “remaining useful life” and “other factors;” and electric reliability. Finally, we note certain resources that are available to facilitate state plan development and implementation.

B. State Plan Performance Periods This section describes state plan requirements related to the timing of achieving the emission guidelines and state plan performance periods. A performance period is a period for which the final plan submittal must demonstrate that the required CO 2 emission performance rates or state CO 2 emission goal will be met. The EPA received significant and diverse comments on both the start date of the interim period and the trajectory of compliance over the interim period. After careful consideration of those comments, we are finalizing a start date of January 1, 2022 for the interim period, and three interim step periods. 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 in 2030. Therefore the final rule requires that interim CO 2 emission performance rates or state CO 2 emission goals be met for the interim period of 2022-2029, and for the three interim step periods (2022-2024, 2025-2027, 2028-2029). The final rule allows*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 689 of 1275

states that choose to meet a state CO 2 emission goal the flexibility to define an alternate trajectory of emission performance between 2022 and 2029 to the steps specified in the rule. States have the option of meeting goals of the state’s choosing for the interim step periods instead of meeting the interim step goals provided in the emission guidelines, as long as meeting the state-determined interim step goals will still

result in the interim state CO 2 emission goal being met on an 8- year average or cumulative basis and the 2030 state CO 2 emission goal is achieved. To be approvable, a state plan submittal must demonstrate that the emission performance of affected EGUs will meet the interim step CO 2 emission performance rates or state CO 2 emission interim step goals on average over the 2022-2024, 2025- 2027, and 2028-2029 periods and the final CO 2 emission performance rates or state CO 2 emission goal no later than 2030. This relatively long planning and implementation period provides states with substantial flexibility regarding methods and timing of achieving emission reductions. States may wish to make adjustments to their implementation approaches along the way, or as conditions change, may need to make adjustments to ensure that their plans achieve the CO 2 emission performance

rates or state CO 2 emission goals as intended. As a result, the agency envisions that the EPA, states and affected EGUs will*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 690 of 1275 have an ongoing relationship in the course of implementing this program. The EPA believes that timing flexibility in implementing measures provides significant benefits that allow states to develop plans that will help achieve a number of goals, including, but not limited to: reducing cost, addressing reliability concerns and addressing concerns about stranded

assets. The EPA received numerous comments regarding the concept of the interim compliance 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 program at 2020. Others stated that the investments necessary to meet the proposed 2020 reduction goals are unachievable in that timeframe or would place too great a burden on affected EGUs and states. Some suggested that the 2020 interim goal step should be eliminated in favor of later start dates, including 2022, 2025, or other years. Other commenters provided input suggesting that

states be allowed to establish their own set of interim guidelines and thereby control their own glide path toward the 2030 goal. As discussed in previous sections, based on comments received, the EPA has adjusted the start date for the interim period to 2022, and is retaining the flexibility for states to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 691 of 1275 establish their own emissions trajectory during the interim period. Because of the additional time provided before the beginning of the interim plan performance period, the EPA has determined that additional assurance that states are making progress in implementing the plan between the time of the state plan submittal and the beginning of the interim period is appropriate. As discussed in detail in section VIII.D, the final rule requires that the state plan submittal include a timeline with all the programmatic 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. States must submit a report to

the EPA in 2021 that demonstrates that the state has met the programmatic 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. If the EPA approves a state plan that includes the required obligation on the state to submit this report, and the state either does not submit the requisite report by July 1, 2021, or the state submits a report demonstrating it has not met the programmatic milestones, the EPA’s approval of the state plan will convert to a disapproval. Per the requirements of CAA section 111(d), the EPA will develop and implement a federal plan in the instance of such*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 692 of 1275 disapproval. Many commenters supported providing incentives for states to deploy CO 2 -reducing investments, such as RE and demand-side EE measures, as early as possible. The EPA recognizes the value of such early actions, and in this final rule is providing states with discretion to credit reductions from the activities, implemented from 2013 onward, in the context of both mass-based and rate-based plans. If a state demonstrates, in its July 1, 2021 report, that it has implemented such early action measures, the EPA will consider its report to be presumptively approvable. See sections VIII.C. and VIII.G for a discussion of state planrequirements related to incentivizing early action under massbased and rate-based plans, respectively.

The EPA has based its determination of the BSER on reductions that are achievable beginning in 2022. For that reason, these guidelines require no reductions to be made by affected EGUs prior to 2022 or by other entities in those states that adopt a state measures plan. At the same time, the EPA has concluded that it is essential to the achievement in a timely and cost-effective way of the emissions reductions required to

meet the CO 2 emission performance rates or, in the alternative, the state goals, that the states and EGUs are rewarded for undertaking investments that yield reductions in the years prior*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 693 of 1275 to 2022. Accordingly, state plans must include a mechanism to

ensure this outcome. For purposes of meeting this requirement, a state plan would be presumptively approvable if it included provisions comprising one of the following elements:

 A commitment to demonstrating plan performance on the basis of averaging its emissions over a 10-year period beginning with emissions from its affected EGUs in 2020, factoring in the state’s projected business as usual emissions (rates)

in 2020 and 2021.

 A mechanism for awarding to affected EGUs allowances or

credits for reductions that would contribute to the state’s

achievement of reductions in 2020 and 2021 that are below its business as usual projected emissions for each of those years, and provided that the state’s emission in 2020 and 2021 not exceed the state’s projected business as usual

level. Nothing in these provisions would have the effect of requiring any particular affected EGU to achieve reductions prior to 2022. In addition, states would have the option for including in their state plans mechanisms as alternatives to those described above for meeting the overall emissions reduction requirements for 2020 and 2021, provided that any*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 694 of 1275 state submitting a plan that included a mechanism as an alternative to the presumptively approvable mechanism(s)

described above could demonstrate that the alternative would achieve the same outcome as the mechanism(s) described above. The EPA is including this state plan requirement for several reasons. Chief among them are those offered by

commenters to the effect that the overall cost of achievement of the 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 mandates reductions or imposes emissions limitations. 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 periods, the EPA should include in the final guidelines provisions that accelerate deployment of RE resources, since in so doing the program would speed achievement of expected reductions in the cost of those technologies commensurate with their accelerated deployment. C. State Plan Approaches

1. Overview Under the final emission guidelines, states may adopt and submit either of two different types of state plans. The first*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 695 of 1275 would apply all requirements for meeting the emission guidelines to affected EGUs in the form of federally enforceable emission standards, 561 which we refer to as an “emission standards” state plan type. The second, which we refer to as a “state measures” plan type, would allow the CO 2 emission performance rates or

state CO 2 emission goals to be achieved in part, or entirely, through state measures 562 that apply to affected EGUs, other entities, or some combination thereof. The state measures plan type also includes a mandatory contingent backstop of federally

enforceable emission standards for affected EGUs that would apply in the event the plan does not achieve its anticipated level of emission performance during the period that the state is relying on state measures. The inclusion of a backstop of federally enforceable measures is legally necessary for a state to meet the requirements of 111(d), which specifically requires a state to submit standards of performance, if the state chooses to adopt the state measures plan type. These two types of state plans and their respective

561 40 CFR 60.21(f) defines “emission standard” as “a legally enforceable regulation setting forth an allowable rate of emissions into the atmosphere, establishing an allowance system, or prescribing equipment specifications for control of air pollution emissions.” 562 “State measures” refer to measures that the state adopts and implements as a matter of state law. Such measures are enforceable only per state law, and are not included in and codified as part of the federally enforceable state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 696 of 1275approaches, either of which could be implemented on a singlestate 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 2 emissions from affected EGUs. Further, as described in detail below, both types of plans are responsive to comments we

received from states and other stakeholders. As described below, the EPA believes that each state is able to satisfy the requirements of the final emission guidelines by implementing a plan that applies all requirements to the affected EGUs in the form of federally enforceable

emission standards that achieve the CO 2 emission performance rates or applicable state CO 2 emission goal. Under the emission standards state plan type, the EPA is finalizing three approaches for state plans:

 rate-based emission standards for affected EGUs, which may include use of emission trading;

 mass-based emission standards for affected EGUs, which may include use of emission trading; and

 other emission standards for affected EGUs in the form of a rate or mass standard that results from application of operational or other standards, such as a limit on total*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 697 of 1275 operating hours of an affected EGU over a specified period

or the retirement of an affected EGU. 563

While the EPA believes that the CO 2 emission performance rates can be met, or states can achieve their CO 2 emission goals, through this first type of state plan, which applies federally enforceable emission standards to affected EGUs, the agency also recognizes that many states have existing or planned programs

that limit CO 2 emissions from affected EGUs or those that replace or avoid generation from affected EGUs and result in CO 2 emission reductions. This includes market-based emission budget trading programs that apply to affected EGUs, such as the programs implemented by California and the RGGI participating states, as well as RE and demand-side EE requirements and programs, such as renewable portfolio standards (RPS), energy efficiency resource standards (EERS), and utility- and state-administered incentive programs for the deployment of RE and demand-side EE technologies and practices. The EPA is providing additional flexibility to states to accommodate such requirements and programs through a “state measures” plan. 564

563 Both rate-based and mass-based emission standards could be implemented by states in different ways, including limits that apply to specific affected EGUs and market-based emission trading programs. These variants are outlined below. 564 Note that emission budget trading programs that meet certain basic design criteria may also be included in an “emission standards” plan, as described below.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 698 of 1275 The state measures plan type is composed of measures adopted and implemented by the state that, at least in part, are not included as federally enforceable components of the plan,

but result in achievement of the CO 2 emission performance rates or the applicable state rate-based or mass-based CO 2 emission goal. These state measures could apply to affected EGUs and/or other entities. In a state measures plan, the state must demonstrate how its state measures (in conjunction with any federally enforceable emission standards for affected EGUs that the state chooses to include as part of the state plan) will

either meet the CO 2 emission performance rates or achieve the

state CO 2 emission goal for affected EGUs. Additionally, the state must include in its state plan a “backstop” that will apply federally enforceable emission standards to affected EGUs

sufficient to meet the CO 2 emission performance rates or state

CO 2 emission goal, if when being implemented the plan fails to achieve the required level of CO 2 emission performance during specified plan performance periods. These backstop federally

enforceable emission standards will assure that affected EGUs

achieve the CO 2 emission performance rates or state CO 2 emission goal per the requirements of CAA section 111(d) if the state measures fail to result in the expected level of emission performance.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 699 of 1275 In addition to providing states the option of developing an emission standards or state measures type plan, the final rulemakes clear that states can adopt either a rate-based or massbased CO 2 emission goal. Further, the EPA notes that for either an emission standards plan or a state measures plan, if a state chooses the option of meeting a state rate or mass CO 2 emission goal, the metric chosen for the goal is independent from the measures that implementing authorities may adopt to achieve them. For example, a state could potentially adopt mass-based emission standards and/or other measures and demonstrate that its plan will achieve a rate-based CO 2 goal. Likewise, a state could adopt rate-based emission standards and/or other measures and demonstrate that its plan will meet a mass-based CO 2 goal. 2. Summary of comments on state plan approaches 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 2 emissions. As documented in the RIA, a rate-based approach would result in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 700 of 1275

a substantial reduction in CO 2 emissions relative to emissions

under a business-as-usual case. 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 approaches, as described below. 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 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 2 emission goalfor affected EGUs, including state RPS, EERS and utilityadministered EE programs. Commenters noted that the portfolio approach would provide states maximum flexibility to take local circumstances, economics and state policy into account when developing their plans.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 701 of 1275 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). 565 Multiple commenters expressed concern about making state requirements and utility programs for RE and

demand-side EE enforceable under the CAA. Some of these commenters supported the state commitments plan approach that the EPA took comment on in the proposal, which was a variant of the portfolio approach. Under the state commitment variant, measures that applied to entities other than affected EGUs would not be federally enforceable under the CAA, but state commitments to implement those measures would be federally enforceable elements of a state plan under the CAA. After considering these comments, the EPA is not finalizing the portfolio approach. However, the EPA is finalizing the state measures plan type, as described below, that would accommodate state choices and allow states to rely upon a variety of

565 Legal concerns with the proposed portfolio approach are explored in section VIII.C.4.d.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 702 of 1275 measures, as was envisioned under the portfolio approach, in a way that meets the statutory requirements of CAA section 111(d). 3. “Emission standards” state plan approach The first type of state plan imposes requirements solely on affected EGUs in the form of federally enforceable emission standards, which we refer to as an “emission standards” plan. This type of state plan, as described below, may consist of rate-based emission standards for affected EGUs; mass-based emission standards for affected EGUs; and other emission

standards for affected EGUs in the form of a rate- or mass-based emission standard that results from application of an operational or other standard. 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, due to the advantages of this approach. 566 Under this approach, the state plan submittal must demonstrate that these federally enforceable emission standards

for affected EGUs will achieve the state CO 2 emission goal or CO 2emission performance rates or the applicable rate-based or massbased state CO 2 emission goal.

566 The legal basis for authorizing trading in emission standards is discussed in section VIII.C.3.d.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 703 of 1275 a. Rate-based approach. The first type of “emission standards” plan approach a state may choose is one that uses rate-based emission standards. Under this plan approach, the plan would include federally enforceable emission standards for affected EGUs, in the form of lb CO 2 /MWh emission standards. A rate-based “emission standards” plan may be designed to

either meet the CO 2 emission performance rates for affected EGUs

or achieve the state’s rate-based CO 2 emission goal for affected

EGUs. A plan could be designed such that compliance by affected

EGUs would achieve either the CO 2 emission performance rates for

affected EGUs or the state rate-based CO 2 emission goal. To meet

the CO 2 emission performance rates, a plan would establishseparate rate-based emission standards for affected fossil fuelfired electric utility steam generating units and stationary combustion turbines (in lb CO 2 /MWh) that are equal to or lower

than the CO 2 emission performance rates in the emission guidelines. To meet a state rate-based CO 2 goal, a plan would establish a uniform rate-based emission standard (in lb CO 2 /MWh) that applies to all affected EGUs in the state. This uniform emission rate would be equal to or lower than the applicable

state rate-based CO 2 goal specified in the final emission guidelines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 704 of 1275 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 2 emission performance rates in the emission guidelines or the state rate-based CO 2 goal for affected EGUs. No further demonstration would be necessary by the state to demonstrate that its plan would achieve the CO 2 emission performance rates or the state’s rate-based CO 2 goal. If a state chose, it could instead apply rate-based emission standards to individual affected EGUs, or to categories of affected EGUs, at a lb CO 2 /MWh rate that differs from the CO 2 emission performance rates or the state’s rate-based CO 2 goal. In this case, compliance by affected EGUs with their emission standards would not necessarily ensure that the collective, weighted average CO 2 emission rate for these affected EGUs meets

the CO 2 emission performance rates or the state’s rate-based CO 2 goal. Under this type of approach, the state would be required to include a demonstration, 567 in the state plan submittal, of how its plan would achieve the CO 2 emission performance rates or applicable state rate-based CO 2 goal. This demonstration would include a projection of the collective, weighted average CO 2 rate

567 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO 2 emission goal is one of the required plan components, as described in section VIII.D.2.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 705 of 1275 it anticipates the fleet of affected EGUs would achieve as a result of compliance with the emission standards in the plan. Once the plan is implemented, if the CO 2 emission performance rates or applicable state rate-based CO 2 goal are not achieved, corrective measures would need to be implemented, as described

in section VIII.F.3. 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 2 emissions at the source level, such as heat rate improvements or fuel switching. Second, a state may implement a market-based emission trading program, which enables EGUs to generate and procure Emission Rate Credits (ERCs), a tradable compliance unit representing one MWh of electric generation (or reduced electricity use) with zero associated CO 2 emissions. These ERCs would be issued by the administering state regulatory body. The state may issue ERCs to affected EGUs that emit below a specified CO 2 emission rate, as well as for measures that provide substitute generation for affected EGUs or avoid the need for generation from affected EGUs. These ERCs may then be used to adjust the reported CO 2 emission rate of an affected EGU when demonstrating compliance with a rate-based emission standard.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 706 of 1275 For each submitted ERC, one MWh is added to the denominator of the reported CO 2 emission rate, resulting in a lower adjusted CO 2 emission rate. Eligible measures that may generate ERCs, as well as the accounting method for adjusting a CO 2 emission rate, are discussed in section VIII.G.1. Requirements for rate-based emission trading approaches are discussed in section VIII.G.3.Quantification and verification requirements for RE and demandside EE programs and projects are discussed in section VIII.G.4. ERCs issued in 2022 or a subsequent year may be carried forward (or “banked”) and used for demonstrating compliance in a future year. 568 For example, an ERC issued for a MWh of RE generation that occurs in 2022 may be applied to adjust a CO 2 emission rate in 2023 or future years without limitation. ERCs may be banked from the interim plan performance period to the final plan performance period. Banking provides a number of advantages while ensuring that the same output-weighted average CO 2 emission rates of the

interim and final state CO 2 goals are achieved over the course of a state plan. Banking provisions have been used extensively in

568 States may also consider issuing ERCs representing MWh generation or savings that occur from 2013-2021. Requirements for including this type of a provision in a state plan are discussed in section VIII.G.1.b.(2).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 707 of 1275 rate-based environmental programs and mass-based emission budget trading programs. 569 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 2 emission rate approach, in that allowing banking will reduce compliance costs. Banking encourages additional emission reductions in the near-term if economic to meet a long-term emission rate constraint, which is beneficial due to social preferences for environmental improvements sooner rather than

later. 570 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 emission rate credits or emission allowances may be used for compliance in the future.

569 Banking under mass-based emission budget trading programs, and the rationale for banking provisions, is addressed below in section VIII.C.3.b.(2)(a). 570 The absence of banking creates an incentive to defer both relatively low-cost and higher-cost CO 2 emission reduction actions until a later period when emission rate limits become more stringent, rather than incentives to undertake the low-cost activities sooner in order to further delay the high cost actions. Under a rate-based emission trading program, banking will encourage ERC providers to generate larger numbers of ERCs in early years of a plan performance period, in anticipation of rising ERC prices over time, when demand for ERCs is expected to increase as rate-based CO 2 emission standards become more stringent.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 708 of 1275 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 consumer price 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. Rate-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. Requirements for rate-based emission trading programs that are included in a state plan are discussed in

detail in section VIII.G.3. This discussion includes requirements for the issuance of ERCs. b. Mass-based approach. 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 on mass CO 2 emissions from affected EGUs that are designed to achieve the

mass-based CO 2 goal for a state’s affected EGUs (see section*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 709 of 1275 VII). 571 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) Mass-based emission standard applied to individual affected EGUs. One pathway a state could take to achieve its mass-based

CO 2 goal would be to apply mass-based emission standards to individual affected EGUs, in the form of a limit on total

allowable CO 2 emissions. These emission standards would be designed such that total allowable CO 2 emissions from all affected EGUs in a state are equal to or less than the state’s

571 The EPA notes that states could also apply mass emission limits on affected EGUs that are designed to achieve a state’s rate-based goal. Under this type of approach, the state would be required to include a demonstration, the state plan submittal, of how its plan would achieve the goal. This demonstration would include a projection of the collective, weighted average CO 2 rate it anticipates the fleet of affected EGUs would achieve as a result of the mass emission limits placed on affected EGUs. Once the plan is implemented, if the rate goal is not achieved for the fleet of affected EGUs as a whole, corrective measures would need to be implemented, as described in section VIII.F.3.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 710 of 1275

mass-based CO 2 goal. The individual affected EGUs would be required to emit at or below their mass-based standard to demonstrate compliance. Under this approach, individual affected EGUs would be required to undertake source-specific measures to

assure their CO 2 emissions do not exceed their assigned emission limit. Affected EGU compliance with the emission standards prescribed under this type of mass-based approach would ensure

that the affected EGUs in a state achieve the state’s mass-based

CO 2 goal. 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. (2) Mass-based emission standard with a market-based emission budget trading program

. A second pathway a state could take to

achieve its mass-based CO 2 goal would be to implement a marketbased emission budget trading program. This type of program provides maximum compliance flexibility to affected EGUs, and as a result, may be attractive to states who choose to implement a mass-based approach in their state plan. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 711 of 1275 up to the established emission budget. 572 Allowances may be distributed to affected emission sources through a number of different methods, including direct allocation to affected sources or auction. These allowances can be traded among affected sources and other parties. The emission standard applied to individual emission sources is a requirement to surrender emission allowances equal to reported emissions, with each allowance representing one ton of CO 2 . (a) Emission budget trading programs that ensure achievement of

a state CO 2 goal. Under the emission standards plan type, a massbased emission budget trading program must be designed such that compliance by affected EGUs would achieve the state mass-based

CO 2 goal. Under this approach, a state plan would establish emission budgets for affected EGUs during the interim and final plan performance periods that are equal to or lower than the applicable state mass-based CO 2 goals specified in section VII. Compliance periods for affected EGUs would also be aligned with the interim and final plan performance periods. This approach

would limit total CO 2 emissions from affected EGUs during the interim and final plan performance periods to an amount equal to

or less than the state’s mass-based CO 2 goal.

572 An emission allowance represents a limited authorization to emit, typically denominated in one short ton or metric ton of emissions.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 712 of 1275 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 2 goal for affected EGUs. No further demonstration would be necessary by the state to demonstrate that its plan would achieve the state’s mass-based

CO 2 goal. For this type of plan, where the emission budget is equal

to or less than the state mass CO 2 goal, 573 the EPA would assess achievement of the state goal based on compliance by affected EGUs with the mass-based emission standards, rather than reported CO 2 emissions by affected EGUs during the interim plan performance periods and final plan performance periods. This approach would allow for allowance banking between performance periods, including the interim and final performance periods outlined in this final rule. This is a typical design element for emission budget trading programs addressing GHG emissions. Allowing allowance banking across plan performance periods, including from the interim period to the final period, provides a number of advantages while ensuring that the same cumulative

emission reductions are achieved over the course of a state plan. Emission budget trading programs with unlimited allowance

573 As specified for the interim plan performance period (including specified levels in interim steps 1 through 3) and the final two-year plan performance periods.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 713 of 1275 banking limit cumulative tonnage emissions over the period in which they are applied. As a result, common program design is to allow allowance banking without limitation, unless there is an environmental reason for not doing so (e.g., for criteria pollutants where timing of emissions is important). As discussed in section VIII.C.3.a above, addressing banking under rate-based emission trading programs, this is because banking reduces the cost of attaining the requirements of the program. In addition, the increased temporal flexibility provided by allowance banking would further help address potential electric reliability concerns, as banked allowances can be used to meet emission limit requirements for an affected EGU. (b) Addressing emission budget trading programs with broader source coverage and other flexibilities. As described in section VIII.C.3.b(2)(a) above, under the emission standards plan type, a mass-based emission budget trading program must be designed such that compliance by affected EGUs would achieve the state

mass-based CO 2 goal. However, emission budget trading programs, including those currently implemented by California and the RGGI participating states, include a number of different design elements. If a state chose, it could apply mass-based emission standards in the form of an emission budget trading program that differs in design from that outlined in section VIII.C.3.b(2)(a)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 714 of 1275 above. However, these types of emission budget trading programs must be submitted as a state measure, rather than incorporated as federally enforceable emission standards, as described below

in section VIII.C.4.c. (c) State plan provisions required for a mass-based emission budget trading program approach

. 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 2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs; provisions for state allocation of allowances; provisions for tracking of allowances, from issuance through submission for compliance; and the process for affected EGUs to demonstrate compliance (allowance “true-up” with reported CO 2 emissions). Mass-based emission standards that take the form of an emission budget trading program must be quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described in more detail at section VIII.D.2. (d) Considerations for mass-based emission budget trading programs. 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 2 goal, states have wide*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 715 of 1275 discretion in the design of such programs, provided the emission standards included in the plan are quantifiable, verifiable, enforceable, non-duplicative, and permanent. A key example is state discretion in the CO 2 allowance allocation methods included in the program. 574 This includes the

methods used to distribute CO 2 allowances and the parties to which allowances are distributed. For example, if a state chose,

it could include CO 2 allowance allocation provisions that provide incentives for certain types of complementary activities, such as RE generation, that help achieve the overall CO 2 emission limit for affected EGUs established under the program. States

could also use CO 2 allowance allocation provisions to provideincentives for early action, such as RE generation or demandside EE savings that occur prior to the beginning of the interim plan performance period in 2022. For example, a state could

include CO 2 allowance allocation provisions where CO 2 allowances are distributed to RE generators based on MWh of RE generation that occurs prior to 2022. Such provisions might be addressed through a finite set-aside of CO 2 allowances that are available for allocation under these provisions. c. Other EGU emission standard approaches. As discussed in

574 Allowance allocation refers to the methods used to distribute CO 2 allowances to the owners or operators of affected EGUs and/or other market participants.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 716 of 1275 further detail in section VIII.D.d.(3) regarding the legal issues and statutory language of CAA section 111(h), the EPA is finalizing that design, equipment, work practice, and operational standards cannot be considered as “standards of performance” for this final rule. However, the third “emission standards” approach a state may elect to use is emission

standards for affected EGUs that result in reduced CO 2 lb/MWh or

total tons of CO 2 affected EGUs because of operational or other standards. Under this approach, the state would include in its state plan an emission standard that is the rate or mass standard that results from the applicable operational or other standard. For example, a state might choose to recognize that an individual affected EGU has plans to retire, and those plans could be codified in the state plan by adopting an emission

standard of 0 CO 2 lb/MWh, or 0 total tons, as of a certain date. The state would thus include in the state plan an emission

standard of 0 CO 2 lb/MWh or 0 total tons for that affected EGU that applies after a specified date. Under a mass-based approach, the state could also include an emission standard (e.g., a mass limit) that reflects the result of a limit on an affected EGU’s total operating hours over a specified period. An approvable plan could apply such emission standards to a subset of affected EGUs or all affected EGUs. As with any plan,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 717 of 1275 the state would need to demonstrate that the plan would achieve the required level of emission performance for affected EGUs, in

either CO 2 lb/MWh or total tons of CO 2 . A plan could also apply

such emission standards to a subset of affected EGUs in the state while applying emission standards to the remainder of affected EGUs in the state. For example, a plan might include an

emission standard of 0 CO 2 lb/MWh reflecting a retirement mandate for one or more affected EGUs in a state and apply a rate-based emission standard equal to the CO 2 emission performance rate or

state’s rate-based CO 2 emission goal to the remainder of affected

EGUs. As with the other two approaches , emission standards under this approach must be quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described

in more detail at section VIII.D.2. d. Legal basis for emission standards approach. The emission standards approach is consistent with the requirements of CAA section 111(d). If a state simply adopts the CO 2 emission performance rates, then the corresponding rate-based emission standards in the state plan establish standards of performance for affected EGUs as required under section 111(d)(1)(A). Similarly, if a state chooses to achieve the rate-based CO 2 emission goal through rate-based emission standards, or to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 718 of 1275

achieve the mass-based CO 2 emission goal through mass-based emission standards, then the set of rate-based emission

standards or the set of mass-based emission standards in the state plan establishes standards of performance for affected EGUs as required under section 111(d)(1)(A). In all three cases, the emission standards must be quantifiable, verifiable, enforceable, non-duplicative and permanent; this ensures that the plan provides for implementation and enforcement of the standards of performance (i.e. the emission standards) as required by section 111(d)(1)(B). Finally, as described in section VIII.B.7.b below, standards of performance may include emission trading. Thus, the credit and allowance trading that is allowed under the emission standards approach is consistent with the statutory requirement that the plan establish standards of performance. e. Legal basis for emissions trading in state plans. There are three legal issues 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 719 of 1275 scheme. Third, we give a similar explanation of the EPA’s interpretation of the same phrase in the context of a mass-based allowance trading scheme. (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 the use of emissions trading in this

rule. 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. In the case of an emission limitation expressed as a mass-based limit, trading takes the form of buying or selling allowances. To reiterate for convenience, the definition of “standard of performance” under CAA section 111(a)(1) is: The term ‘standard of performance’ means 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 and any nonair quality health and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 720 of 1275 environmental impact and energy requirements) the Administrator determines has been adequately

demonstrated. Both an emission rate that may be met through tradable ERCs, and a requirement to retire tradable allowances qualify as a “standard for emissions.” The term “standard” is not defined, but its everyday meaning is a rule or requirement, 575 which,

under either a Chevron step 1 or step 2 analysis, would include an emission rate that may be met through tradable ERCs and a requirement to retire tradable allowances. 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.” 576 In addition, in the 1995 Municipal Solid Waste (MSW) Combustor rule the EPA authorized emission trading by sources. 577

575 E.g., “Something that is set up and established by authority as a rule for the measure of quantity, weight, value, or quality.” Webster’s Third New International Dictionary 2223 (1993). 576 70 FR 28606, 28616-17 (May 18, 2005). 577 60 FR 65387, 6540/2 (Dec. 19, 1995).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 721 of 1275 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, e.g., a rate that must be met on an annual basis. Similarly, an allowance requirement applies continuously in that the source is continuously under an obligation to assure that at the appropriate time, it will have enough allowances to cover its emissions. In this respect, a tradable emission rate or allowance requirement is similar to a non-tradable emission rate that must be met over a specified period, such as one year. In all of these cases, a source is continuously subject to its requirement although it may be able to emit at different levels at different points in time. It should also be noted that a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 722 of 1275 tradable emission rate or allowance program is appropriate for

CO 2 emissions, the air pollutant covered by this rule, because

CO 2 emissions do not cause short-term health or welfare dangers; rather, their effects occur over a longer term. (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. Here, we explain our interpretation of the phrase “provides for implementation and enforcement of [the] standards of performance” in the context of the integrity of a trading system for ERCs under a rate-based approach. As described previously, the EPA has legal concerns regarding whether 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 does not run afoul of these legal concerns, as neither the requirements of section 111(d) nor of the federally enforceable state plan extend to non-EGU generators or third-party verifiers*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 723 of 1275 of such compliance units. In the Legal Memorandum we also discuss specific legal issues regarding EM&V criteria, EM&V plans, and Projection guidance. (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. Our interpretation of the phrase “provides for implementation and enforcement of [the] standards of performance” in the context of the integrity of a trading system for allowances under a mass-based approach is further explained in the Legal Memorandum. 4. “State measures” state plan type 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 2 emission performance rates or rate-based or mass-based*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 724 of 1275

state CO 2 goals by imposing federally enforceable requirements on affected EGUs. Upon further consideration of the requirements of CAA section 111(d), and in consideration of the comments we received on the proposed portfolio approach and the variation of the state commitments approach, the EPA is finalizing the state measures plan type in addition to the emission standards plan type. The EPA believes the state measures plan type will provide states with additional flexibility to accommodate existing or planned programs that involve measures implemented by the state, or by entities other than affected EGUs, that result in avoided generation and CO 2 emission reductions at affected EGUs. The EPA believes this second state plan type will afford states with appropriate flexibility while meeting the statutory requirements of CAA section 111(d). 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 725 of 1275and the RGGI participating states in the Northeast and MidAtlantic. 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 578 in achieving the required level of CO 2 emission performance from affected EGUs. The state measures under this plan type could be measures involving entities other than affected EGUs, or a combination of such measures with emission standards for affected EGUs, so long

as the state demonstrates that such measures will result in

achievement of the CO 2 emission performance rates or applicable

state CO 2 emission goal. The EPA notes that under this plan type, a state could also choose to include any emission standards for affected EGUs as federally enforceable requirements in the state plan to be implemented alongside or in conjunction with state measures the state would implement and enforce. For a state measures plan to be approvable, it must include a demonstration of how the measures, whether state measures or state measures in conjunction with any federally enforceable emission standards, will achieve the CO 2 emission performance

578 “State measures” refer to measures that the state adopts and implements as a matter of state law. Such measures are enforceable only per applicable state law, and are not included in the federally enforceable state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 726 of 1275

rates or state CO 2 emission goal for affected EGUs. However, because the state measures would not be federally enforceable emission standards, the plan must also include a “backstop” of federally enforceable emission standards, in order for the state measures plan type to satisfy the requirement of CAA section 111(d) that a state submit standards of performance for affected EGUs. This backstop would impose federally enforceable emission

standards on the state’s affected EGUs in the case that the state measures fail to achieve the required CO 2 emission performance rates or CO 2 emission goal. The backstop, discussed further below, would assure that the CO 2 emission performance

rates or state CO 2 emission goals are fully achieved by affected EGUs in the form of federally enforceable emission standards. a. Requirements for state measures under a state measures plan

. 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 727 of 1275 The EPA would assess the overall approvability of a plan using a state measures plan type 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 either the CO 2 emission performance rates or the CO 2 emission goal for the state’s affected EGUs. This includes a demonstration of adequate legal authority and funding to implement the state plan and any associated measures. The EPA’s determination that such a plan is satisfactory would be based in part on whether the state measures are adequately described in the supporting documentation and the plan submittal demonstrates that the statemeasures are quantifiable, verifiable, enforceable, nonduplicative and permanent as described above. This is necessary for the EPA to ensure that the results achieved through the plan are quantifiable and verifiable, and to assess whether the state measures are anticipated to achieve the CO 2 emission performance

rates or state CO 2 emission goal for affected EGUs. EPA’s evaluation of the approvability of a state measures plan would also include assessing whether the backstop comprised of federally enforceable emission standards for the state’s affected EGUs, in the case that the state measures fail to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 728 of 1275 achieve the required CO 2 emission performance rates or CO 2 emission goal, would assure that the CO 2 emission performance

rates or state CO 2 emission goals are fully achieved by affected EGUs. The trigger for the backstop must also satisfactorily provide for the implementation of the backstop emission

standards. b. Considerations for the state measures plan type backstop. As further discussed in section VIII.C.4.c, the EPA believes a backstop, composed of federally enforceable emission standards

for the affected EGUs that are sufficient to achieve the state

CO 2 emission goal or meet the CO 2 emission performance rates in the event that state measures do not result in the anticipated

CO 2 emission performance, is necessary for the state measures plan type to meet the requirements of CAA section 111(d). The state plan must specify the backstop that would apply federally

enforceable emission standards to the affected EGUs if the state measures plan does not achieve the anticipated level of CO 2 emission performance by affected EGUs. The state plan must include promulgated regulations (or other requirements) that fully specify these emission standard requirements, which must be quantifiable, verifiable, enforceable, non-duplicative and permanent. These requirements are described in more detail at

section VIII.D.2.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 729 of 1275 These federally enforceable emission standards must be designed such that compliance by affected EGUs with the emission

standards would achieve the state’s rate-based or mass-based interim and final goals for affected EGUs, or the CO 2 emission performance rates. The emission standards must specify CO 2 emission performance levels (in rate or mass) that would apply for the interim plan performance period (including specifying levels for each of the interim step 1 through step 3 periods) and the final two-year plan performance periods. 579 The backstop emission standards must also make up for any

shortfall in CO 2 emission performance during a prior plan performance period that led to triggering of the backstop, which is discussed further below. The state may effectuate this by submitting, along with the backstop emission standards, provisions to adjust the emission standards to account for any prior emission performance shortfall, such that no modification of the emission standards is necessary in order to address the emission performance shortfall. Examples of such provisions are discussed below. The state may also address the requirement to make up for any shortfall in CO 2 emission performance by

579 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 two-year periods).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 730 of 1275 submitting as part of the final plan backstop emission standards

that assure affected EGUs would achieve the state’s rate-based

or mass-based interim and final CO 2 goals for affected EGUs, or

the CO 2 emission performance rates, and then later submit appropriate revisions to the backstop emission standards adjusting for the shortfall through the state plan revision

process. The federally enforceable backstop emission standards for affected EGUs could be designed by the state to take the form of rate-based emission standards, mass-based emission standards, or other emission standards, as described above for emission standards plan types. Alternatively, the backstop emission standards could be based on the federal plan, using the federal plan regulations as a model rule. The state measures plan must also specify the trigger and conditions under which the backstop federally enforceable emission standards would apply. The trigger and attendant conditions for deployment of the backstop would address the CAA section 111(d) requirement that states submit a program 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 731 of 1275 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 two-year final plan performance period (2030-2031, and subsequent two-year periods). If actual

CO 2 emission performance by affected EGUs exceeds the specified level of emission performance by 10 percent or more during a specified interim or final plan performance period, the state measures plan must require that the backstop federally enforceable emission standards would take effect and be applied to affected EGUs. In the event of such an exceedance, the state measures plan must provide that such emission standards would be

effective within 18 months of the deadline for the state’s submission of its periodic report to the EPA on state plan implementation and performance, as described in section

VIII.D.2.c. 580 While the state is taking any necessary administrative and technical actions to implement the backstop emission standards regulations that were promulgated as part of the state plan, state measures must remain in effect and continue to be implemented by the state until such time as the backstop emission standards are effective.

580 States may choose to establish an effective date for backstop emission standards that is sooner than 18 months.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 732 of 1275 As described above, the federally enforceable emission standards for affected EGUs must be designed to ensure that the

CO 2 emission performance rates or a state’s interim and final CO 2 goals are achieved. This includes specifying CO 2 emission performance levels (in rate or mass) during the interim and final plan performance periods, as well as inclusion of provisions to automatically adjust those emission performance levels as appropriate to make up for any CO 2 emission performance shortfall during a prior plan performance period that led to triggering of the backstop. For example, assume a plan identified a mass-based CO 2 standard for affected EGUs of 100 million tons during the interim step 1 performance period (2022-2024), 90 million tons during the interim step 2 performance period (2025-2027), and 80 million tons during the interim step 3 performance period (2028- 2029. Over the entire interim plan performance period (2022- 2029), the interim mass-based CO 2 goal is cumulative emissions of

270 million tons. Assume that CO 2 emissions from affected EGUs in the interim step 1 period were actually 115 million tons, triggering implementation of the backstop. In this instance, the mass-based standard for affected EGUs implemented as part of the backstop during subsequent plan performance periods would need

to ensure that cumulative CO 2 emissions during the 2022-2029*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 733 of 1275 interim period do not exceed 270 million tons. This could be achieved, for example, by implementing a mass standard of 75 million tons during the interim step 2 performance period (rather than the 90 million tons originally specified in the plan), or some other combination during the remaining interim step 2 and 3 performance periods. 581 The emission standards included in the plan must specify calculations for how such adjustments will be made. A similar approach could be applied for a rate-based plan. For example, assume the identified emission performance level during the interim step 1 performance period is 1,000 lb CO 2 /MWh and the emission performance level during the interim step 2 performance period is 900 lb CO 2 /MWh. Further assume that affected EGUs actually emit at a rate of 1,150 lb CO 2 during the interim step 1 plan performance period. The backstop could apply

an emission standard of 750 lb CO 2 /MWh during the subsequent interim step 2 plan performance period (rather than the 900 lb

CO 2 /MWh specified in the emission standard) to make up the emission performance shortfall that led to triggering of the backstop.

581 In this example, states could elect to implement different combinations of mass-based standards during the remaining interim step 2 and 3 plan performance periods, provided that cumulative CO 2 emissions during the full interim plan performance period (2022-2029) do not exceed 270 million tons.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 734 of 1275 c. Addressing emission budget trading programs under the state measures plan type. As described in section VIII.C.3.b(2)(a) above, under the emission standards plan type, a mass-based emission budget trading program must be designed such that compliance by affected EGUs would achieve the state mass-based

CO 2 goal. However, emission budget trading programs, including those currently implemented by California and the RGGI participating states, include a number of different design elements. 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.C.3.b(2)(a) above. However, these types of emission budget trading programs must be submitted as a state measure, rather than incorporated as federally enforceable emission standards,

as described below. Such 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), 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 735 of 1275 containment reserve provisions that make additional allowances available at specified allowance prices. 582 In the case where an emission budget trading program contains such elements, compliance by affected EGUs with the mass-based emission standards would not necessarily ensure that

CO 2 emissions from affected EGUs do not exceed the state’s massbased CO 2 goal. The EPA has determined that such emission budget trading programs, which may include broader scope of covered emission sources and the types of provisions described above that functionally expand an established emission budget, may be implemented as part of a state measures plan. A description of the state measures plan type and related requirements is provided in section VIII.C.4. Under this type of approach, the state would be required to include a demonstration, 583 in its state plan submittal, of how its plan would achieve the state mass-based CO 2 goal. This

582 For example, both the California and RGGI programs allow for the use of allowances awarded to GHG offset projects to be used to meet a specified portion of an affected emission source’s compliance obligation. The RGGI program contains a cost containment allowance reserve that makes available additional allowances up to a certain amount, at specified allowance price triggers. 583 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO 2 goal is one of the required plan components, as described in section VIII.D.2.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 736 of 1275 demonstration would include a projection of the total CO 2 emissions from the fleet of affected EGUs that would occur as a result of compliance with the emission standards in the plan.

Section VIII.D.2 discusses how such demonstrations could address design elements of emission budget trading programs with broader scope and additional compliance flexibility mechanisms, such as those included in the California and RGGI programs. Once the plan is implemented, if the mass-based CO 2 goal is not achieved during a plan performance period, the backstop federally enforceable emission standards included in the state plan that apply to affected EGUs would be implemented, as described in

section VIII.C.4.b. 584 d. Legal basis for state measures plan type. 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

584 Achievement of the state mass-based CO 2 goal would be determined based solely on stack CO 2 emissions from affected EGUs. Where a state program includes the ability of an affected emission source to use GHG offsets to meet a portion of its allowance compliance obligation, no “credit” is applied to reported CO 2 emissions by the affected EGU. The use of offset allowances or credits in such programs merely allows an affected EGU to emit a ton of CO 2 in the amount of submitted offset allowances or credits. In all cases, there is no adjustment applied to reported stack emissions of CO 2 from an affected EGU when determining compliance with its emission limit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 737 of 1275 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.” Under the state measures plan, a state must submit a state plan that includes standards of performance for CO 2 emissions from affected EGUs in the form of a federally enforceable backstop. Section 111(d) unambiguously allows a state to submit a plan that establishes standards of performance for certain sources, but does not mandate when such standards of performance must be in effect or implemented in order to meet applicable compliance deadlines. The EPA believes because the statute does not provide such a mandate, the EPA therefore has the discretion under section 111(d) to determine the effective date of standards of performance submitted under state plans to meet the requirements of this rule. Where the statute is silent, the EPA has authority to provide a reasonable interpretation, under the U.S. Supreme Court’s decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842–844 (1984). The EPA’s interpretation is that for states that submit state plans establishing standards of performance under section 111(d), the effective date of such standards of performance may be later in time, perhaps indefinitely, for a number of reasons and under certain conditions. The Legal Memorandum discusses in more detail why*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 738 of 1275

the EPA believes it is reasonable to defer the effective date for standards of performance for affected EGUs as long as

affected EGU CO 2 emissions are projected to achieve, and do achieve, the requisite state goal. Section 111(d)(2)(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 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, i.e. the standards of performance, by putting the backstop into effect once the associated trigger is deployed. In other words, when the CO 2 performance level under a state plan exceeds the trigger as described in section VIII.C.4.b, the emission standards that were submitted as the federally enforceable backstop and any attendant requirements must be implemented and in effect. The statutory requirement under CAA section 111(d)(2) regarding enforcement is also satisfied under the state measures plan by the state submitting standards of performance, in the form of the backstop, for inclusion as part of the federally enforceable state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 739 of 1275 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 CO 2 emission performance rates or requisite state CO 2 emission performance goal. The state measures plan type differs from the proposed portfolio approach, however, in that the measures involving entities other than affected EGUs are not included as part of the federally enforceable 111(d) state plan, but the state may rely upon such measures that have the effect of reducing CO 2 emissions from

affected EGUs as a matter of state law. The EPA took comment on the proposed portfolio approach and the utilization of measures on entities other than affected EGUs in meeting the requirements of the emission guidelines and CAA section 111(d), and is finalizing the state measures plan type upon careful consideration of statutory requirements and comments received. On May 20, 2015, the Ninth Circuit Court of Appeals issued

a decision in Committee for a Better Arvin et al. v. US EPA et

al. , Nos. 11-73924 and 12-71332, that, at first glance, might be thought to conflict with the state measures approach. The court held that the EPA violated the Clean Air Act by approving a California state implementation plan (SIP) which relied on emission reductions from state-only mobile source standards*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 740 of 1275 (“waiver measures”) without including those standards in the SIP. The court first looked at the plain language of section 110(a)(2)(A) of the Act, which states that SIPs “shall include”

the emission limitations and other control measures on which a state relies to comply with the Act. The court then stated that

the EPA’s action was also inconsistent with the structure of the Act. The EPA has the primary responsibility to protect the nation’s air quality, but in the court’s view, the EPA itself would be unable to enforce the state-only standards. In addition, the court stated that the EPA’s action was inconsistent with citizens’ right to enforce SIP provisions

under section 304. 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), does not specifically say that every emission reduction measure must be “included” in the state plan and be made federally enforceable. We interpret the state measures approach to satisfy these requirements by establishing a backstop that is the standard of performance and providing for its implementation and enforcement through the federal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 741 of 1275 enforceability of the trigger and backstop. The Ninth Circuit’s structural analysis also does not apply. The availability of the trigger and backstop gives the EPA and citizens a federally enforceable route to ensure that all necessary emission reductions take place in order to achieve the standards of performance. This is markedly different than the state-only standards, where according to the Ninth Circuit, the EPA and citizens had no route to ensure that all necessary emission reductions took place in order to attain the NAAQS. In addition, case law suggests that federal enforceability for every requirement may not be necessary when there are sufficient federally enforceable requirements to satisfy the statute, see National Mining Ass'n v. United States EPA, 59 F.3d 1351 (D.C.Cir. 1995); in this case federal enforceability for the stateonly measures is not necessary to meet the statutory requirements of section 111(d)(1) as the federally enforceable trigger and backstop are sufficient. e. Legal concerns with proposed portfolio approach. 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. After reviewing comments, the EPA agrees with commenters that legal questions remain as to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 742 of 1275 whether measures that impose federally enforceable requirements

on entities other than affected EGUs either constitute “standards of performance” or “provide[] for the implementation and enforcement of . . . standards of performance” under CAA section 111(d)(1). In addition, shortly after publication of the proposed rulemaking, the U.S. Supreme Court issued the UARG decision, which cautions against new extensions of CAA jurisdiction to large segments of the economy, and raises additional questions as to whether entities other than affected EGUs may be included in section 111(d) plans and thereby subject

to CAA enforcement authorities. Utility Air Regulatory Group v.

EPA , 134 S. Ct. 2427 (2014) (“UARG v. EPA”) The state measures plan type the EPA is finalizing is a logical outgrowth of the comments received on the proposed portfolio approach. As previously explained, legal questions remain as to whether federally enforceable state plans under section 111(d) can include 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. The EPA is reasonably interpreting 111(d) as authorizing the state measures plan type, and believes this plan type is also responsive to, and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 743 of 1275 accommodating of, states and stakeholders who have expressed the importance of being able to rely upon various measures that have the effect of resulting in CO 2 reductions from affected EGUs. 5. Multi-state plans 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, 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 2 emission performance rates or state CO 2 emission goals are achieved.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 744 of 1275 The EPA is finalizing two approaches that allow states to coordinate implementation in order to meet the emission guidelines. 585 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 2 goals and submit a plan that will achieve a joint CO 2 emission goal for the fleet of affected

EGUs located within those states. 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. This approach facilitates interstate emission trading without requiring states to submit joint plans. 586

585 The EPA notes that in addition to these approved approaches, other types of multi-state approaches may be acceptable in an approvable plan, provided the obligations of each state under the multi-state plan are clear and the submitted plan(s) meets applicable emission guideline requirements. 586 States may submit individual plans with such linkages, or if they choose, provide a joint submittal. Forms of joint submittals are described at section VIII.E.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 745 of 1275 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. Summary of comments on multi-state plans. Multiple commenters supported the EPA’s proposed approach that allows states to implement a multi-state plan to meet a joint CO 2 emission goal. However, a number of states commented that states should also be allowed to coordinate without aggregating multiple individual state goals into a single joint goal. Many states questioned the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 746 of 1275 incentives that a state would have to aggregate its goal with other states that have different goals. 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 above 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 747 of 1275 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 manyreasons, including features that support reliability. Marketbased 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 limits. 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. Multistate coordination through a joint emission goal. Multiple states may submit a multi-state plan that achieves an aggregated joint CO 2 emission goal for the affected EGUs in the participating states. 587 The joint emission goal approach is

587 As a conceptual and legal matter, the relationship between states coordinating to meet a joint CO 2 emission goal under this rule is similar to the relationship between states coordinating SIP submissions to attain the NAAQS in an interstate nonattainment area. In both cases, the states coordinate their actions in a way that, cumulatively, the measures applicable in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 748 of 1275 acceptable for both types of state plans, the “emission standards” plan type and the “state measures” plan type. However, the EPA is requiring that a joint goal may apply only to states implementing the same type of plan, either an “emission standards” plan or a “state measures” plan. 588 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 2 emission rate based on the individual rate-based goals for each of the participating states and 2012 generation from affected EGUs. A mass-based multi-state plan would include an aggregated mass-based CO 2 emission goal for

each state will lead to achievement of a common interstate goal (with the EPA evaluating the sufficiency and success of the plans on a holistic, interstate basis). Despite the shared goal, in both cases, the mere fact of coordination has no effect on each state’s sovereign legal authority. For example, the legally applicable rules in a given state are adopted by that state individually, not by a joint entity or other interstate mechanism. Similarly, the fact that the states coordinate their rules does not grant them the authority to directly enforce each other’s rules, or to take direct legal action against a state that is failing to implement its own rules. Although some states may jointly submit their coordinated rules to the EPA as a matter of administrative convenience, the state rules within such a plan are nothing more than reciprocal laws of the sort that states routinely enact in voluntary coordination with each other

. 588 This is necessary because if the joint goal is not achieved during a plan performance period, different remedies would apply under an emission standards plan and a state measures plan. Under an emission standards plan, corrective measures would apply. Under a state measures plan, the federally enforceable backstop emission standards would be triggered.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 749 of 1275 the participating states, in cumulative tons of CO 2 , derived by summing the individual mass-based CO 2 emission goals of the participating states. Such plans could include emission standards in the form of a multi-state rate-based or mass-based emission trading

program. 589 Alternatively, states could submit a multi-state plan using a state measures approach. 590 Both approaches could provide for implementation of a multi-state rate-based or mass-based emission trading program. c. Multi-state coordination among states retaining individual state goals. States that do not wish to pursue a joint CO 2 emission goal with other states may pursue a second pathway to multi-state collaboration. States may submit plans that will meet an individual state goal for affected EGUs, but include implementation in coordination with other state plans by

589 A potential example of this approach is the method by which the states participating in RGGI have implemented individual CO 2 Budget Trading Program regulations in a linked manner using a shared emission and allowance tracking system. Each state’s regulations implementing RGGI stand alone on a legal basis, but provide for the use of CO 2 allowances issued in other participating states for compliance under the state regulations. These states are not listed by name in state regulations, which instead refer to participating states that have established a corresponding CO 2 Budget Trading Program regulation. More information is available at http://www.rggi.org. 590 Under this approach, a state measure could include, if a state chose, a multi-state emission trading program that is enforceable at the state level.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 750 of 1275 providing for the interstate transfer of ERCs or CO 2 allowances, depending on whether the state is implementing a rate-based or mass-based emission trading program. This form of coordinated implementation may occur under both an “emission standards” type of plan and a “state measures” type of plan, where states are implementing rate-based or mass-based emission trading

programs. 591 Under this approach, a state plan could indicate that ERCs

or CO 2 allowances issued by other states with an EPA-approved state plan could be used by affected EGUs for compliance with the state’s rate-based or mass-based emission standard, respectively. Such plans must indicate how ERCs or emission allowances will be tracked from issuance through use by affected EGUs for compliance, 592 through either a joint tracking system, interoperable tracking systems, or an EPA-administered tracking system. 593

591 ERCs may only be transferred among states implementing ratebased emission limits. Likewise, emission allowances may only be transferred among states implementing mass-based emission limits. 592 Referred to in different programs as “surrender,” “retirement,” or “cancellation.” 593 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 programs. The EPA is exploring options for providing such support and is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 751 of 1275 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. 594 However, the EPA would also assess linkages with other state plans, to ensure that the joint tracking system or interoperable tracking systems used to implement rate-based or mass-based emission trading programs across states are properly designed with necessary components, systems, and procedures to maintain the integrity of the linked emission trading programs. (1) Multi-state coordination: rate-based emission trading programs. 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

conducting an initial scoping assessment of tracking system support needs and functionality. 594 Note that for mass-based plans, the approvability requirements for a state plan would differ, depending on the structure of the emission budget trading program included in the state plan. For example, approvability requirements and basic accounting with regard to whether a plan achieves a state’s mass CO 2 goal would differ for emission budget trading programs that cover only affected EGUs subject to CAA section 111(d) vs. programs that apply to a broader set of emission sources. These considerations are addressed in subsection VIII.C.5.c.(2)(c).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 752 of 1275 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. 595 When demonstrating that a state’s CO 2 emission goal is achieved as a result of plan implementation, a state with linkages to other states would be required to demonstrate that any ERCs issued by another state that are used by affected EGUs in the state for compliance with its rate-based CO 2 emission standards were issued by states with an EPA-approved state plan. 596 States could implement these linkages among state plans with rate-based emission trading systems through three different applied implementation approaches: (1) plans that are “ready-

595 The emission standards in each individual state plan must include regulatory provisions that address the issuance of ERCs and tracking of ERCs from issuance through use for compliance, as described in subsection VIII.G.3. The description here addresses how those regulatory provisions will be implemented through the use of a joint tracking system, interoperable tracking systems, or an EPA-administered tracking system. 596 This could be done by reference to data in the tracking system used to implement a state’s rate-based emission trading program that identifies the origin of each ERC (e.g., by serial identifier).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 753 of 1275 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:

 Ready-for-interstate-trading plans: A state plan recognizes ERCs issued by any state with an EPA-approved plan that also uses a specified EPA-approved 597 or EPA-administered tracking system. Plans are approved individually. A state plan need not designate the individual states by name from which it would accept issued ERCs. States can join such a coordinated approach over time, without the need for plan

revisions.

 Specified bilateral linkage: States recognize ERCs issued by named partner states. Partner states must demonstrate that they use a shared tracking system, interoperable tracking systems, or an EPA-administered tracking system. Plans are approved individually, including review of the shared tracking system or interoperable tracking systems.

 Joint ERC issuance: States implement materially consistent

597 The EPA would designate tracking systems that it has determined adequately address the integrity elements necessary for the issuance and tracking of ERCs, as described in subsection VIII.C.5.c.(1). Under this approach, a state could include in its plan such a designated tracking system, which has already been reviewed by the EPA.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 754 of 1275 rate-based emission trading program regulations and share a tracking system. States coordinate their review of

submissions for ERC issuance 598 and their issuance of ERCs to the shared tracking system. Issued ERCs are recognized as usable for compliance in all states using the shared tracking system. Plans are approved individually, including review of the shared tracking system. 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. 599

598 This refers to eligibility applications and monitoring andverification reports, which are required submittals for nonaffected EGU entities seeking the issuance of ERCs. Where affected EGUs are issued ERCs for emission performance below a specified CO 2 emission rate, these ERCs are issued by the individual state in which they are subject to a rate-based emission standard. Requirements for ERC issuance are discussed in subsection VIII.G.3. 599 The EPA also notes that individual state plans may utilize RE and demand-side EE (and other eligible measures), that occur in other states, as described in section VIII.G.1 addressing interstate effects. Under an individual state plan, ERCs could be issued for RE and demand-side EE measures that occur in other states, provided the EE/RE provider submits the measures to thestate and the measures meet requirements in the state’s ratebased emission trading program requirements. The multi-state approaches described above provide additional flexibility for states to informally and formally coordinate their*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 755 of 1275 (2) Multi-state coordination: mass-based emission trading programs. An individual state may provide for the use of CO 2 allowances issued by another state(s) for compliance with the mass-based emission standards in its plan. This type of state plan would include regulatory provisions that enable affected EGUs to use allowances issued in other states for compliance under the state’s emission budget trading program. This type of state plan must also indicate how CO 2 allowances will be tracked from issuance through use for compliance, through either a joint tracking system, interoperable tracking systems, or use of an EPA-administered tracking system. 600 Two different implementation approaches could be used tocreate such links. A state could submit a “ready-for-interstatetrading” 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.

implementation of rate-based plans across states while retaining individual rate-based state goals. 600 The emission standards in each individual state plan must include regulatory provisions that address the issuance of CO 2 allowances and tracking of CO 2 allowances from issuance through use for compliance, as described in subsection VIII.C.3.b.(2)(c). The description here addresses how those regulatory provisions will be implemented through the use of a joint tracking system, interoperable tracking systems, or an EPA-administered tracking system.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 756 of 1275 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. These considerations are discussed in section VIII.B.5.c.(2)(a) below. 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. 601 State plans using a specified EPA-approved tracking system would be deemed by the EPA as ready for interstate linkage upon approval of the state plan. No additional EPA approval would be necessary for states to link their emission budget trading programs, and affected EGUs in those states could engage in interstate trading subsequent to EPA plan approval. A state would indicate in its plan submittal that its

601 The EPA would designate tracking systems that it has determined adequately address the integrity elements necessary for the issuance and tracking of emission allowances, as described in subsection VIII.C.5.c.(2). Under this approach, a state could include in its plan such a designated tracking system, which has already been reviewed by the EPA.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 757 of 1275 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 planrevisions if the plan is not already structured as ready-forinterstate-trading), without requiring all of the existing 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 758 of 1275 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 in order to maintain the integrity of the linked programs. 602 (a) Considerations for linked emission budget trading programs. 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. Differences in approval criteria are necessary to ensure that each individual state plan demonstrates it will

602 Depending on the specific regulatory provisions in the emission standards in their approved state plans, participating states may also need to revise their implementing regulations (and by extension their state plans) to accept CO 2 emission allowances issued by new partner states as usable for compliance with their mass-based emission standards.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 759 of 1275

achieve a state’s mass-based CO 2 emission goal for affected EGUs. The accounting applied to individual plans to assess whether a

state achieves its mass-based CO 2 goal will also differ, based on whether an emission budget trading program includes only

affected EGUs or a broader set of emission sources. These considerations are addressed below, for both types of emission budget trading programs. (i) Links among emission budget trading programs that only include affected EGUs. Where the emission budget trading programs in each plan apply only to affected EGUs subject to CAA section 111(d), and include compliance timeframes that align with the interim and final plan performance periods, both planswould functionally be meeting an aggregated multi-state massbased goal, but without formally aggregating the goal. CO 2 emissions from affected EGUs in both states could not exceed the

total combined CO 2 emission budgets under the emission standards in the two states. A net “import” of CO 2 allowances from one

state would mean that allowable CO 2 emissions in the other net “exporting” state are less than that state’s established emission budget. On a multi-state basis, CO 2 emissions from

affected EGUs could not exceed the sum of the states’ emission budgets. Under this approach, if the emission budget for the mass-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 760 of 1275 based emission standard in each plan is equal to or lower than

the state’s mass-based CO 2 goal, compliance by affected EGUs with

the mass emission standard in a state 603 would ensure that cumulatively the mass CO 2 goals of the linked states are achieved. As a result, achievement of an individual state’s mass

CO 2 goal would be assessed by the EPA based on compliance by

affected EGUs with the mass-based emission standards in the state plan, rather than reported CO 2 emissions by affected EGUs

in the state. 604 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, as described below. In all cases, where a state plan includes an emission budget trading program that applies only to affected EGUs, and includes compliance timeframes that align with plan performance periods, achievement of a state mass CO 2 goal will be assessed by the EPA based on whether affected EGUs comply with the mass-based emission standard, rather than

603 Compliance by an affected EGU with the emission standard is demonstrated based on surrender to the state of a number of CO 2 allowances equal to its reported CO 2 emissions. 604 This approach is warranted because under such linked programs, CO 2 emissions from affected EGUs in one state that exceed a state’s mass CO 2 goal would be accompanied by CO 2 emissions from affected EGUs in another linked sate that are below that state’s mass CO 2 goal.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 761 of 1275 reported CO 2 emissions from affected EGUs. (ii) Links with emission budget trading programs that include a broader set of emission sources. State plans may include emission budget trading programs that include affected EGUs as

well as other non-affected emission sources. 605 Generally, as described in section VIII.C.3-4 above, such plans must demonstrate that the mass-based CO 2 goal for affected EGUs in a state will be achieved, as a result of implementation of the emission budget trading program. 606 Where such a program is linked with other programs, the state plan must include a

demonstration that the mass-based CO 2 goal will be achieved, considering the emission allowance links with other programs. The EPA, in determining the approvability of each state’s plan under this approach, would evaluate the linkages between plans. Specifically, the EPA would evaluate whether the linkages would enable the EGUs in each participating state to meet the state’s applicable mass-based CO 2 goal.

605 This may apply under both an emission standards plan and a state measures plan. 606 Under a program that applies to affected EGUs and other emission sources, compliance by affected EGUs with the emission standard – a requirement to surrender emission allowances equal to reported emissions – will not assure that a state’s CO 2 mass goal is achieved. As a result, a further demonstration is required in the plan that compliance by affected EGUs with the program will result in CO 2 emissions from affected EGUs that are at or below a state’s CO 2 mass goal.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 762 of 1275 During plan implementation, the EPA would assess whether

the affected EGUs in a state achieved the state’s mass-based CO 2 goal as follows. Reported CO 2 emissions from affected EGUs under such plans must be at or below a state’s mass-based CO 2 emission goal during an identified plan performance period, with the following state accounting adjustments for net “import” and net “export” of CO 2 allowances:

 Net “imports” of CO 2 allowances: Reported CO 2 emissions from affected EGUs in a state may exceed the state CO 2 mass goal during an identified plan performance period in the amount of an adjustment for the net “imported” CO 2 allowances during the plan performance period. The adjustment represents the CO 2 emissions (in tons) equal to the number of net “imported” CO 2 allowances. 607 Under this adjustment, such allowances must be issued by a state with an emission budget trading program that only applies to affected EGUs. Net “imports” of allowances are determined through review of tracking system compliance accounts.

 Net “exports” of CO 2 allowances: Reported CO 2 emissions from affected EGUs in a state during an identified plan performance period must be equal to or less than the CO 2

607 Net “imports” and “exports” of CO 2 allowances are defined and explained below.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 763 of 1275 mass goal minus an adjustment for the “exported” CO 2 allowances during the plan performance period. The adjustment represents CO 2 emissions (in tons) equal to the number of net “exported” CO 2 allowances. Net “exports” of allowances are determined through review of tracking system compliance accounts.

Where CO 2 emissions from affected EGUs exceed these levels (based on reported CO 2 emissions with applied plus or minus adjustments for net CO 2 allowance “imports” or “exports”) by 10 percent or more, a state would be considered to not have met its

CO 2 mass goal during an identified plan performance period. As a result, under a state measures state plan, implementation of the backstop federally enforceable emission standards for affected EGUs in the state plan would be triggered.

A net transfer of CO 2 allowances during a plan performance period represents the net number of CO 2 allowances (issued by a respective state) that are transferred from the compliance accounts of affected EGUs in that state to the compliance

accounts of affected EGUs in another state. 608 This net transfer

608 A net transfer metric is applied as of the end of the plan performance period. This net accounting as of a specified date is necessary because multiple individual allowance transfers may occur among accounts during a plan performance period, representing normal trading activity. In addition, net transfers are based on compliance account holdings, because these*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 764 of 1275 is determined based on compliance account holdings at the end of the plan performance period. 609 For example, assume two states, State A and State B, with emission budgets of 1,000 tons of CO 2 . Each state issues 1,000 CO 2 allowances. At the end of a plan performance period, affected EGUs in State A collectively hold

500 CO 2 allowances in their compliance accounts that were issued by State A. Affected EGUs in State B collectively hold in their compliance accounts 500 CO 2 allowances issued by State A and 1,000 CO 2 allowances issued by State B. In this simplified example, a net transfer of 500 CO 2 allowances has occurred between State A and State B. State A has “exported” 500 CO 2 allowances to State B, while State B has “imported” 500 CO 2 allowances from state A. d. Multi-state plans that address a subset of EGUs in a state.

represent the CO 2 allowances directly available at that point in time for use by an affected EGU for complying with its emissionlimit. Emission budget trading programs typically allow nonaffected entities to hold allowances in general accounts. These parties are free to hold and trade CO 2 allowances, providing market liquidity. General account holdings are not assessed as part of a periodic state net transfer accounting, as these allowances may subsequently be transferred to other accounts in multiple states and do not represent allowances currently held by an affected EGU that can be used for complying with its emission limit. 609 Compliance account holdings, as used here, refer to the number of CO 2 allowances surrendered for compliance during a plan performance period, as well as any remaining CO 2 allowances held in a compliance account as of the end of a plan performance period.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 765 of 1275 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 subject

affected EGUs in different ISOs or RTOs to 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 766 of 1275 address the affected EGUs owned and operated by a utility with a multi-state service territory. e. Legal issues regarding multi-state plans. While nothing in section 111(d)(1) explicitly authorizes states to adopt and submit multi-state plans and for the EPA to approve them as satisfactory, nothing in section 111(d)(1) explicitly prohibits this, 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. D. State Plan Components and Approvability Criteria 1. Approvability Criteria 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 767 of 1275

EGU CO 2 emissions; 2. The enforceable measures must be projected to achieve emission performance equivalent to or better than the applicable

CO 2 emission performance rates or state-specific CO 2 goal on a timeline equivalent to that in the emissions guidelines;

3. The EGU CO 2 emission performance must be quantifiable and verifiable; 4. The plan must include a process for state reporting of plan implementation, CO 2 emission performance outcomes, and implementation of corrective measures, if necessary. 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), which results in no functional change in the approvability criteria or the components of a state plan addressed in the proposal. We do not expect this change to have a substantive*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 768 of 1275 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. 610 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 solar thermal programs, waste heat recovery, net-metering energy savings and state RPSs.

610 The existing guidance documents referenced were: (1) September 23, 1987 memorandum and accompanying implementing guidance, “Review of State Implementation Plans and Revisions for Enforceability and Legal Sufficiency;” (2) August 5, 2004“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures;” and (3) July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable Energy Policies and Programs into State and Tribal Implementation Plans, Appendix F.”*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 769 of 1275 These enforcement considerations arose primarily under the proposed portfolio approach for state plans. In this action, the EPA is finalizing the state measures approach instead of the portfolio approach described in the proposed rule. As explained in section VIII.C, the EPA is not finalizing the portfolio approach, which would have allowed state plan submittals to include federally enforceable measures that apply to entities that are not affected EGUs. However, 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 federally enforceable backstop which requires the affected EGUs to meet emission standards that fully

achieve the CO 2 emission performance rates or the state’s CO 2 emission goal if the state measures do not meet the intended emission performance levels. Because the EPA is not finalizing the portfolio approach, which would have allowed states to include enforceable measures in a state plan that apply to entities that are not affected EGUs, the agency is not providing additional guidance on federal enforceability of measures that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 770 of 1275 might apply to such entities. As proposed, we are requiring that state plans include a demonstration that plan measures are enforceable, which for emission standard plans is discussed in section VIII.D.2.b.4 below and for state measures plans is

discussed in section VIII.D.2.c.6 below. 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 the state CO 2 emission goal. Additionally, a commenter requested that the enforceability mechanisms that the EPA requires in state plans should support existing programs, as well as new programs in other states, by minimizing program changes required purely to conform with federal requirements, while still providing enough additional program review and accounting to ensure that CO 2 emission

reductions are achieved. These and related comments contributed to the EPA’s decision to finalize the option for states to submit a state measures plan, which would be comprised, at least in part, of measures implemented by the state that are not included as federally enforceable components of the plan, with a 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 CO 2 emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 771 of 1275 performance levels specified in the plan on schedule. For more information on the state measures plan approach, see section VIII.C.4 of this preamble above. 2. Components of a state plan submittal In this action, the EPA is finalizing that a state plan submittal must include the components described below. The 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 the 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 approach” plan or a “state measures approach” plan. States may also opt to submit a plan that meets

the CO 2 emission performance rates for affected EGUs or achieves

a state rate-based or mass-based CO 2 emission goal. The content*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 772 of 1275 of the state plan submittal will vary depending on which approach the state decides to adopt. States that choose to participate in multi-state plans must adequately address plancomponents that apply to all participating states in the multistate plan. 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 approach. Section VIII.D.2.c addresses additional components required for submittals under the state measures plan approach. a. Components required for all state plan submittals. 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 approach) or VIII.D.2.c (for the state measures plan approach) of this

section. (1) Description of the plan approach and geographic scope. The description of the plan approach must indicate whether the state will meet the emission guidelines on an individual state basis or jointly through a multi-state approach, and whether the state is adopting an emission standards approach plan or a state measures approach plan. For multi-state plans this component must identify all participating states and geographic boundaries*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 773 of 1275 applicable to each component in the plan submittal. (2) Identification of interim period emission performance rates or state goal (for 2022-2029), interim step performance rates or interim state goals (2022-2024; 2025-2027; 2028-2029) and final emission performance rates or state goal (2030 and beyond). The state plan submittal must indicate whether the plan is designed

to meet the CO 2 emission performance rates or the state CO 2 emission goal. As noted in the emission guidelines, the EPA is finalizing state goals in the form of a CO 2 emission rate (emission rate-based goal) and in the form of tonnage CO 2 emissions (mass-based goal). The state may adopt either the

rate-based or the mass-based state CO 2 emission goal provided in the emission guidelines. If the state chooses the option of developing a plan that achieves the state CO 2 emission goal, the state plan submittal must identify the rate-based or mass-based

CO 2 emission goal that must be achieved through the plan (expressed in numeric values, including the units of measurement, such as pounds of CO 2 per net MWh of useful energy output or tons of CO 2 ). The plan submittal must identify the

state CO 2 interim period goal (for 2022-2029), interim steps goals (interim step goal 1 for 2022-2024; interim step goal 2 for 2025-2027; interim step goal 3 for 2028-2029) and final CO 2 emission goal of 2030 and beyond.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 774 of 1275 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. 611 States are free to establish different interim step goals than those the EPA has specified in this final rule. If states choose to determine their own interim step goals, the state must demonstrate that it will still meet the interim goal for 2022-2029 finalized in this action and the plan submittal must include in its supporting documentation a description of the analytic process, tools, methods, and assumptions used to

make this demonstration. The final rule allows states the opportunity to switch from

a rate-based CO 2 goal for the interim plan performance period (2022-2029) to a mass-based CO 2 goal for the final plan performance period (2030 and onward). Conversely, a state plan may use a mass-based CO 2 goal for the 2022-2029 interim period,

and a rate-based CO 2 goal for the final goal plan performance periods. Some commenters requested that flexibility be provided to allow states to switch from rate-based goals to mass-based

611 In this action, the EPA is providing interim state goals in the form of a CO 2 emission rate (emission rate-based goal) and in the form of tonnage CO 2 emissions (mass-based goal).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 775 of 1275 goals either as a one-time change between the interim goal to the final goal, or more frequently if necessary year-by-year. The EPA recognizes that it may be necessary to switch between rate-based goals and mass-based goals, and therefore provides the option for states to change approaches between the interim plan performance period and the final plan performance period. To ensure progress toward the goals, maintain consistency with rule provisions, and minimize delays due to plan revisions, the EPA does not grant states the ability to change approaches more often than from the interim period to the final period. For instance, if a state plan indicates that a mass-based CO 2 goal will be used for demonstrating achievement of the interim goal, then that state will be required to demonstrate achievement of the specified mass-based interim steps on a mass basis, and will have the option to change to a rate-based approach for the final plan performance period. 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 emission rate based on the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 776 of 1275 individual rate-based goals for each of the participating statesand 2012 generation from affected EGUs. For a mass-based multistate plan, the joint goal would be a sum of the individual mass-based goals of the participating states, in tons of CO 2 . The plan submittal must include in its supporting documentation a description of the analytic process, tools, methods, and assumptions used to calculate the joint multi-state goal. (3) Applicability of state plans to affected EGUs. The state plan submittal must list the individual affected EGUs that meet the applicability criteria of § 60.5805 and provide an inventory

of CO 2 emissions from those affected EGUs for the most recent calendar year prior to plan submission for which data are

available. (4) Monitoring, reporting and recordkeeping requirements for affected EGUs. The state plan submittal must specify how each emission standard is quantifiable and verifiable by describing

the CO 2 emission monitoring, reporting and recordkeeping requirements for affected EGUs. The applicable monitoring, recordkeeping and reporting requirements for affected EGUs with

are outlined in section VIII.F. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 777 of 1275 following the date of each occurrence, measurement, maintenance, corrective action, report or record. Commenters requested clarification of the record retention requirements for states vs. for affected EGUs and also requested that the EPA clarify onsite vs. offsite record maintenance requirements for affected EGUs. Consistent with state recordkeeping requirements, 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, occurrence, measurement, maintenance, corrective action, report, or record.,

that 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) State reporting and recordkeeping requirements. 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 2 emission performance rates or state CO 2 emission goal.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 778 of 1275 The EPA is finalizing state reporting requirements based on the type of plan approach the state chooses to adopt and implement. These state reporting requirements are discussed in section VIII.D.2.b (for emission standards approach) and VIII.D.2.c (for state measures approach). 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 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. 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 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. An approvable final state plan submission must include a requirement for the state to submit this report to the EPA no later than July 1, 2021. If the EPA approves a state plan that includes the required obligation on the state to submit this report, and the state either does not submit the requisite report by July 1, 2021, or*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 779 of 1275 the state submits a report demonstrating it has not met the programmatic milestones, the EPA’s approval of the state plan will convert to a disapproval. Per the requirements of CAA section 111(d), the EPA will develop and implement a federal plan in the instance of such disapproval. As discussed in section VIII.B, if a state demonstrates, in its July 1, 2021 report, that it has implemented such early action measures, the EPA will consider its report to be presumptively approvable. The EPA is finalizing a requirement for states to electronically submit state plan submittals, any supporting materials that are part of a state plan submittal, and state 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) (http://www.epa.gov/cdx/). See Section VIII.E.7 for additional information on electronic submittal requirements. In the June 2014 proposal, the EPA proposed that states must keep records at minimum for 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 emission standards. The EPA received multiple comments recommending that the EPA reduce recordkeeping*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 780 of 1275 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 five 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 steps 1, 2 and 3 and the interim plan period from 2022- 2029. After 2029, states must keep records of all information relied upon in support of any continued demonstration that the

final CO 2 emissions performance rates or goals are being achieved. The EPA agrees with comments that a 20-year record retention requirement could be unduly burdensome, and has reduced the length of the record retention requirement for the final rule. During the interim period, states must keep records for 10 years from the date of conclusion of each compliance period for its EGUs and/or plan performance period. During the final period, states must keep records for 5 years from the date of conclusion of each compliance period for its EGUs and/or plan performance period. All records must be in a form suitable and readily available for expeditious review. States must also keep*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 781 of 1275 records of all data submitted by each affected EGU that was used to determine compliance with each affected EGU’s emission standard, and such data must meet the requirements of the emission guidelines, except for any information that is submitted to the EPA electronically pursuant to requirements in 40 CFR part 75. If the state is adopting and implementing the state measures approach, the state must also maintain records of all data regarding implementation of each state measure and all

data used to demonstrate achievement of CO 2 emission performance

rates or CO 2 emission goal and such data must meet the requirements of the emission guidelines. The EPA finds that these final recordkeeping requirements balance the need to maintain records while reducing the strain on state resources. (6) Certification of hearing on state plan. For the final plan submittal, states must meaningfully engage with all members of the public, including communities, during the plan development process. The existing implementing regulations regarding public participation requirements are in40 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. In its plan submittal, a state must provide certification that the state gave reasonable notice and opportunity for public comment on the state plan. The state must demonstrate that the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 782 of 1275 public hearing on the state plan was held only after reasonable notice, which will be considered to include, at least 15 days prior to the date of such hearing, notice given to the public by prominent advertisement announcing the date(s), time(s) and place(s) of such hearing(s). For each hearing held, a state plan submittal must include in the supporting documentation the 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 the implementing regulations at 40 CFR 60.23. Additionally, the EPA recommends that states work with local municipalities, community-based organizations and the press to advertise their state hearing(s). 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. Also as discussed in this rule, effects from this rule can be anticipated to impact communities in various ways. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 783 of 1275

such communities. The EPA notes that meaningful public involvement goes beyond the holding of a public hearing. In section VIII.E, the EPA provides states with resources on how to engage with affected 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 website and toll-free number that all stakeholders, including affected communities, can access to get more information regarding the upcoming hearing(s). In addition, the EPA recommends that states provide all communities with a mechanism on their website and on the toll-free number 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 affected communities about the upcoming public hearing(s). (7) Supporting documentation. The state plan submittal must provide supporting material and technical documentation related to applicable components of the plan submittal. (a) Legal authority. In its submittal, a state must adequately demonstrate that it has the legal authority (regulations/legislation) and funding to implement and enforce*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 784 of 1275 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 the necessary authority to enter into a multi-state agreement. (b) Technical documentation. 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, multi-state goal calculation (if joint multi-state demonstration), analytical materials used in projecting CO 2 emission performance that will be achieved through the plan, relevant implementation materials and any additional technical requirements and guidance the state proposes to use to implement elements of the plan. (c) Programmatic milestones and timeline. As part of the state*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 785 of 1275 plan supporting documentation, the state must include in its submittal a timeline with all the programmatic 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. The programmatic milestones and timeline should be appropriate to the overall state plan approach included in the state plan

submittal. (d) Reliability. As discussed in section VIII.H.2, each state must demonstrate that it has considered reliability issues while developing its plan. b. Additional components required for the emission standards approach. The EPA is finalizing requirements that a final plan submittal using the emission standards approach must contain the following components, in addition to the components discussed in

section VIII.D.2.a. (1) Identification of federally enforceable emission standards for affected EGUs. The state plan submittal must include federally enforceable emission standards that apply to affected EGUs. The emission standards must meet the requirement of component 2 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 786 of 1275 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 two calendar years. States can choose to set shorter schedules of compliance for the emission standards but no longer than the compliance periods the EPA is finalizing in this rulemaking. 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 2 is long-lived in the atmosphere, and this rulemaking is focused on performance standards related to those long-term impacts. For state plans in which affected EGUs may rely upon the use of ERCs for meeting a rate-based federally enforceable emission standard, the emission standards in the state plan must include requirements addressing the issuance, tracking and use for compliance of ERCs consistent with the requirements in the emission guidelines. The state plan must also demonstrate that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 787 of 1275 the appropriate ERC tracking infrastructure that meets the requirements of the emission guidelines will be in place to administer the state plan requirements regarding ERCs and document the functionality of the tracking system. State plan requirements must include provisions to ensure that ERCs are properly tracked from issuance to submission for compliance. The state plan must also demonstrate that the MWh for which ERCs are issued are properly quantified and verified, through state EM&V and other verification plan requirements that meet the requirements in the emission guidelines. Rate-based emission standards must also include monitoring, reporting, and recordkeeping requirements for CO 2 emissions and useful energy output for affected EGUs; and related compliance demonstration requirements and mechanisms. All of these requirements are

discussed in more detail in sections VIII.G.3 and 4. For state plans using a mass-based emission trading program approach, the emission standards in the state plan must include requirements that specify the emission budget and related compliance requirements and mechanisms. These requirements must

include: CO 2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs; provisions for state allocation of allowances; provisions for tracking of allowances, from issuance through submission for compliance; and the process for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 788 of 1275 affected EGUs to demonstrate compliance (allowance “true-up” with reported CO 2 emissions.) (2) Demonstration that each emission standard is quantifiable, non-duplicative, permanent, verifiable and enforceable. 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. 612 An emission standard is non-duplicative with respect to an affected EGU if it is not already incorporated in another stateplan, except in instances where incorporated as part of a multistate 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 CO 2 emission rate of an

612 CO 2 continuous emissions monitoring system (CEMS) is the most technically reliable method for EGUs. CEMS provide a measurement method that is performance based rather than equipment specific which is verified based on NIST traceable standards. CEMS provide a continuous measurement stream that can account for variability in the fuels and the combustion process. Reference methods have been developed to ensure that all CEMS meet the same performance criteria which helps to ensure a level playing field and consistent, accurate data.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 789 of 1275 affected EGU, except in the case of a multi-state plan where CO 2 emission performance is demonstrated jointly for all affected EGUs subject to the multi-state plan. 613 This does not mean that

measures in an emission standard cannot also be used for other purposes. For example, a MWh of electric generation from a wind turbine could be used by an electric distribution utility to comply with state RPS requirements and also be used by an affected EGU comply with emission standard requirements under a state plan. Another example is when actions taken pursuant to CAA section 111(d) requirements can satisfy other CAA program requirements (e.g., Regional Haze requirements, MATS etc.) 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,

613 For example, an ERC that is issued by a state under its ratebased emission standards may be used only once by an affected EGU to adjust its reported CO 2 emission rate when demonstrating compliance with the emission standards. However, an ERC issued in one state could be used by an affected EGU to demonstrate compliance with emission standards in another state, where states are collaborating in the implementation of their individual emission trading programs through interstate transfer of ERCs or CO 2 emission allowances, or participating in a multistate plan with a rate-based or mass-based emission trading program. These coordinated multi-state approaches are addressed in subsection VIII.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 790 of 1275 measure, and verify compliance with it. An emission standard is enforceable if it: (1) 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, (4) each compliance activity or measure is practically enforceable in accordance with EPA guidance on practical enforceability, 614 and the Administrator and the state maintain the ability to enforce against violations and secure appropriate corrective actions pursuant to CAA sections 113(a)– (h), and states and other third parties maintain the ability to enforce against violations and secure appropriate corrective actions pursuant to CAA section 304. 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. 615 These guidance documents serve as the

614 See prior footnote. 615 The EPA guidance on enforceability includes: (1) September 23, 1987, memorandum and accompanying implementing guidance, “Review of State Implementation Plans and Revisions for Enforceability and Legal Sufficiency,” (2) August 5, 2004,“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures,” and (3) July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 791 of 1275 foundation for the types of monitoring, reporting, and emission standards that the EPA has found can be, as a practical matter,

enforced. 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 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 616 and based on the requirements of CAA section 304. We are finalizing a requirement for a demonstration that states and other third parties can enforce against violations of an emission standard included in a state plan via civil action as part of the required plan component demonstrating enforceability. We are finalizing this requirement as a logical outgrowth of proposal preamble text, the proposal preamble citation to existing enforceability guidance documents that discuss this requirement,

Energy Policies and Programs into State and Tribal Implementation Plans, Appendix F.” 616 State Plan Considerations technical support document for theClean Power Plan Proposed Rule: http://www2.epa.gov/carbonpollution-standards/clean-power-plan-proposed-rule-state-planconsiderations.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 792 of 1275

and comments received. (3) Demonstration that the emission standards contained in the plan achieve the CO 2 emission performance rates or state CO 2 emission goal. A state plan submittal must demonstrate that the federally enforceable emission standards on affected EGUs are

sufficient to meet either the CO 2 emission performance rates or

the state’s CO 2 emission goals in the emission guidelines for the interim and final periods. This includes the interim period of 2022-2029, including interim step 1 2022-2024 period; interim step 2 2025-2027 period and interim step 3 2028-2029 period (or

alternative CO 2 emission performance step levels adopted by the state, provided they result in achievement of the CO 2 emission performance rates or state CO 2 emission goal during the 2022-2029 interim period), as well as the final period of 2030 and beyond. The type of demonstration required for emission standards plans will vary depending on how the CO 2 emission performance standards are applied across the fleet of affected EGUs in a state, as

described below. (a) Demonstration for a rate-based emission standards state plan. The type of demonstration for a rate-based emission standards plan depends on the design of the plan submitted to

the EPA. When a state submits an emission standards plan that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 793 of 1275 establishes separate rate-based CO 2 emission standards for affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines (in lbs CO 2 /MWh) that are equal to or lower than the CO 2 emission performance rates in the emission guidelines, then no additional demonstration is required beyond inclusion of the emission standards in the plan. Under this approach, compliance by affected EGUs with the

emission standards will ensure that the CO 2 emission performance

rates or the state rate-based CO 2 emission goal is achieved. If a state chose to instead apply rate-based emissionperformance standards to individual affected EGUs, or to subcategories of affected EGUs (such as fossil fuel-fired electric utility steam generating units and stationary combustion turbines), at a lb CO 2 /MWh rate that differs from the CO 2 emission performance rates or the state’s rate-based CO 2 goal, then a further demonstration is required that application of the

CO 2 emission standards will achieve the CO 2 emission performance

rates or state rate-based CO 2 goal in the emission guidelines. The state must demonstrate through a projection that the weighted average CO 2 emission rate of affected EGUs, when weighted by generation (in MWh), will be equal to or less than

the CO 2 emission performance rates or the state's rate-based CO 2 emission goal. This projection must address both the interim*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 794 of 1275 period (including interim step periods 1-3, for 2022-2024, 2025- 2027, and 2028-2029), and the final period (2030-2031, and subsequent two-year periods). The projection in a state plan must include the following key information, at a minimum:

 a summary of each affected EGU’s anticipated future operation characteristics, including annual generation, CO 2 emissions, capacity and capacity factors;

 planned retirements;

 anticipated use of ERCs to adjust the reported CO 2 emission rate of affected EGUs, including but notlimited to, anticipated use (in MWh) by technologytype (e.g., wind, solar, demand-side EE), the physical location of the resources providing ERCs, and any other relevant information (e.g., power purchase agreements (PPAs) and other long-term power contracts); and an explanation, with calculation, of how these measures are being used in the projection to adjust the CO 2 emission rate of affected EGUs;

 expected electricity demand growth at the state or regional level, including the source and basis for these estimates (e.g., based on population growth, GDP, adoption of demand-side EE or other applicable*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 795 of 1275 factors); if demand growth is not from NERC, an ISO or RTO, EIA or other publicly available source, then the projection must include justification and assumptions that inform the demand growth used;

 expected fuel switching at affected EGUs;

 heat rate improvements; and

 any other applicable assumptions used in the projection. Because electricity flows across state boundaries, single state plan demonstrations must explain any regional information considered in developing the assumptions. Multi-state plans or plans sharing common elements should use regional assumptions or demonstrate reconciliation of any inconsistencies between state-level assumptions. (b) Demonstration for a mass-based emission standards state plan. Under the emission standards plan type, a mass-based emission budget trading program must be designed such that compliance by affected EGUs would achieve the state mass-based

CO 2 goal. Under this approach, a state plan establishes emission budgets for affected EGUs during the interim and final plan performance periods that are equal to or lower than the applicable state mass-based CO 2 goals specified in the final emission guidelines. Compliance periods for affected EGUs are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 796 of 1275 also aligned with the interim and final plan performance periods. This approach limits total CO 2 emissions from affected EGUs during the interim and final plan performance periods to an amount equal to or less than the state’s mass-based CO 2 goal. 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 2 goal for affected EGUs. No further demonstration is necessary by the state to demonstrate that its plan would achieve the state’s mass-based CO 2 goal. For this type of plan, where the emission budget is equal

to or less than the state mass CO 2 goal, 617 the EPA will assess achievement of the state goal based on compliance by affected EGUs with the mass-based emission standards, rather than reported CO 2 emissions by affected EGUs during the interim plan performance periods and final plan performance periods. This approach allows for allowance banking between performance periods, which is a typical design element for emission budget trading programs addressing GHG emissions. (4) State reporting requirements. After consideration of the comments received regarding state reporting requirements, the EPA is finalizing for state plans using the emission standards

617 As specified for the interim plan performance period (including specified levels in interim steps 1 through 3) and the final two-year plan performance periods.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 797 of 1275 approach that a state report is due to the EPA no later than the July 1 following the end of each reporting period. For the interim period (2022-2029) the EPA is finalizing the following interim reporting periods: interim step 1 covers the three calendar years 2022-2024; interim step 2 covers the three calendar years 2025-2027 and interim step 3 covers the two calendar years 2028-2029. A biannual state report is required starting in 2030 and beyond covering the two calendar years of each reporting period. The EPA believes this final reporting schedule will reduce the reporting frequency for states implementing the emission standards approach. 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 2 emission performance by affected EGUs during the reporting period. The state report must include compliance demonstrations for affected EGUs and identify whether affected EGUs are on schedule to meet the applicable CO 2 emission performance rate or emission goal during the performance periods and compliance periods, as specified in the state plan. As discussed in more detail in section VIII.F, in each report during the interim period (2022-2029), the state must include an interim performance check. The interim performance*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 798 of 1275 check will compare the CO 2 emission performance level identified in the state plan for the applicable interim step period versus

the actual CO 2 emission performance achieved by affected EGUs during the period. Starting in 2032, the biannual state report must include a final performance check to demonstrate that the

state continues to meet the final CO 2 emission performance rates

or state rate-based or mass-based CO 2 goal. For states using the emission standards approach, if actual

CO 2 emission performance by affected EGUs exceeds the specified

level of CO 2 emission performance in the state plan by 10 percent or more during any of the specified interim step reporting periods or during a final plan reporting period (after 2030), the state report must include a notification to the EPA that corrective measures have been triggered. Corrective measures are

discussed in detail in section VIII.F. c. Additional components required for the state measures approach. 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. (1) Identification of federally enforceable emission standards for affected EGUs (if applicable). If applicable, the state plan submittal must include any federally enforceable CO 2 emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 799 of 1275 standards that apply to affected EGUs, and demonstrate that those emission standards meet the requirements that apply in the context of an emission standards approach, discussed in the preceding section VIII.D.2.b. Specifically, the state plan submittal must demonstrate that each federally enforceable emission standard is quantifiable, non-duplicative, permanent

and verifiable. (2) Identification of backstop of federally enforceable emission standards. A state measures plan must include a backstop of federally enforceable emission standards for affected EGUs that fully achieve the CO 2 emission performance rates or the state’s

interim and final CO 2 emission goal if the state plan fails to

achieve the intended level of CO 2 emission performance. The backstop emission standards could be based on the federal plan, using the federal plan regulations as a model rule. For the federally enforceable backstop, the state plan submittal must identify the federally enforceable emission standards for affected EGUs, demonstrate that those emission standards meet the requirements that apply in the context of an emission standards approach, discussed in the preceding section, identify a schedule and trigger for implementation of the backstop that is consistent with the requirements in the emission guidelines and identify all necessary state administrative and technical*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 800 of 1275 procedures for implementing the backstop (e.g. how and when the state would notify affected EGUs that the backstop has been triggered). Aspects of the backstop are discussed in detail in

section VIII.C.4.b. (3) Identification of state measures. A state adopting a state measures plan approach 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 CO 2 emission performance rates or state goal, the applicable state laws or regulations related to such measures, and identification of parties or entities implementing such state measures. The state must also include in its supporting documentation the schedule and milestones for the implementation of the state measures. A state measures plan submittal that relies upon RE and demand-side EE programs and projects must also demonstrate in its supporting documentation that the minimum EM&V requirements apply to those programs and projects. (4) Demonstration that the standards and/or measures are projected to achieve the CO 2 emission performance rates or state

CO 2 emission goal. A state plan submittal must demonstrate that the federally enforceable emission standards for affected EGUs, if included, and state measures, are sufficient to attain the CO 2 emission performance rates or state rate-based or mass-based CO 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 801 of 1275 emission goal for the interim period of 2022-2029 and the final period of 2030 and beyond. The elements required in the state demonstration will vary depending on the design of the state plan, as described below in this section. (a) Demonstration for a state measures state plan. A state measures plan submittal must demonstrate that the state measures, whether alone or in conjunction with any federally

enforceable CO 2 emission standards, will achieve either the CO 2 emission performance rates or the state rate-based or mass-based

CO 2 goals in the emission guidelines for the interim and final periods. This includes the interim period of 2022-2029, including interim step 1 2022-2024 period, interim step 2 2025- 2027 period, and interim step 3 2028-2029 period (or alternative

CO 2 emission performance step levels adopted by the state, provided they result in achievement of the CO 2 emission performance rates or state CO 2 emission goal during the 2022-2029 interim period), as well as the final period of 2030 and beyond. A satisfactory demonstration of the future CO 2 performance of quantifiable and verifiable state-enforceable measures must use technically sound quantification methods that are reliable and replicable. The demonstration must be supported by the methods and measurement procedures by which the federally

enforceable CO 2 emission standards for affected EGUs are reliably*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 802 of 1275 measured, if these standards are incorporated into the state measures state plan. In addition, the demonstration must include details about individual state-enforceable measures (or bundled measures), timing for implementation and future MWh impacts of these measures. The future performance of affected EGUs must be based on verifiable and quantifiable energy and emissions quantification methods accompanied with underlying analytical assumptions and verifiable data sources used to demonstrate

future CO 2 performance by affected EGUs under this type of state plan. A satisfactory state measures plan demonstration must

include a state measures CO 2 performance projection that shows how the measures in the state plan, alone or in conjunction with federally enforceable CO 2 emission standards, will achieve the

future CO 2 performance at affected EGUs. Elements of this projection must include the following for the interim and final periods:

 An explanation of the tools and emission quantification approaches used in the projection (described in section VIII.D.2.c.(4)(b).

 State Measures Plan CO 2 Performance Projection that includes all state measures and/or emission standards in the state plan (see the State Plans Technical*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 803 of 1275 Support Document for details).

 Underlying assumptions used in the projection (as described below in sections VIII.D.2.c.(4)(b),(c) and (d). (b) Emission quantification approaches and tools. The EPA received comments on whether we would require specific modeling tools and input assumptions. Commenters raised concerns that the EPA may require states to use proprietary models because many

states do not have the financial resources to conduct their own modeling using utility dispatch models or capacity expansion models. The EPA is not requiring a specific type of emission quantification approach or model, as long as the one chosen uses technically sound methods that establish a clear relationship between electricity grid interactions of the state enforceable measures, affected EGU dispatch, generation cost and operations within the time frame outlined in these guidelines. Emission quantification methodologies could range from historical estimates using growth rate or statistical analysis to electric sector energy modeling. If a state chose to include supplemental material on emission baseline projections, then the emissions quantification method used for both the baseline projection and state measure plan scenario should be similar. A state should include an explanation of how the emission quantification method*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 804 of 1275 works and the associated tool(s) that employ the method, as well as an explanation for why the methodology and tool chosen is best suited for an electric sector analysis of affected EGUs for the interim period and final period. The results in the demonstration must be verifiable and reproducible using the documented assumptions described in the following paragraph. The projections of EGU dispatch and generation can differ from the EPA’s forecast in the RIA, but should have a clear relationship between future electricity demand, costs and generation capacity to establish the projected future CO 2 emissions from affected EGUs. The following assumptions demonstrating the relationship between the state measures and CO 2 emission performance of affected EGUs should be documented and explained: projected CO 2 emission rates in lbs/MWh; projected CO 2 emissions; projected generation at the EGU in MWhs; fuel prices, when applicable; heat rates for each affected EGU; wholesale electricity prices, when available; projected emission limits and/or rates as a result of environmental or economic constraints; planned retirements; planned new generation; fuel switches at affected EGUs; fixed operations and maintenance costs, when applicable; variable operations and maintenance costs, when applicable; and planning reserve margins, when applicable.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 805 of 1275(c) Elements of a rate-based state measures plan. Under a ratebased state measures plan, MWh from state enforceable qualifying measures may be used to adjust the CO 2 emission rate of affected EGUs when demonstrating achievement of the CO 2 emission performance rates or the state rate-based CO 2 goal in the emission guidelines. The state plan would include the following key information, at a minimum, to demonstrate the rate-based state measures plan for affected EGUs are commensurate with the state’s goal:

 a summary of each affected EGU’s anticipated future operation characteristics, including annual generation, CO 2 emissions, capacity and capacity factors;

 planned retirements;

 a detailed description of the zero CO 2 emitting demandside EE savings and RE generation (and any other qualifying MWh) from state measures that will be available for use in adjusting the reported CO 2 emission rates of affected EGUs, including, but not limited to, the amount of generation or savings by technology-type (e.g., wind, solar, EE), the physical location of the EE measures or RE generation, and any other relevant information (e.g., power purchase*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 806 of 1275 agreements (PPAs) and other long-term power contracts); and an explanation, with calculation, of how these measures are being used in the projection to adjust the CO 2 emission rate of affected EGUs;

 expected electricity demand growth at the state or regional level, including the source and basis for these estimates (e.g., based on population growth, GDP, adoption of demand-side EE or other applicable factors); if demand growth is not from NERC, an ISO or RTO, EIA or other publicly available source, then the projection must include justification and assumptions that inform the demand growth used;

 expected fuel switching at affected EGUs;

 heat rate improvements; and

 any other applicable assumptions used in the projection. In the state plan demonstration, the state must show the calculation of this adjustment from these state enforceable actions at their affected EGUs either in aggregate or at each affected EGU. As specified in section VIII.G, the zero-emitting

MWhs of EE and RE can be added to the denominator of the

emission rate of the affected EGUs. The demonstration should illustrate this arithmetic adjustment for rate-based state*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 807 of 1275 measure plans.(d) Elements of a mass-based state measures plan. Under a massbased state measures plan, a state must demonstrate that the combined state-enforceable measures, along with any federally

enforceable CO 2 emission standards for affected EGUs, if included, will achieve the state mass-based CO 2 goal. Because these measures could have varying degrees of impact on CO 2 emissions from affected EGUs, the approach a state chooses to quantify projected emissions impacts should have the capability

to demonstrate how the combined state enforceable measures are impacting CO 2 emissions at affected EGUs so that the sum of

emissions at all affected EGUs will be lower than or achieve the

state’s CO 2 emission goal for each specified time period in the emission guidelines. The EPA is not requiring a specific method or tool, but clear documentation of assumptions and explanation of methods used, as discussed in section VIII.D.2.c and in the State Plans Technical Support Document, must be included in a satisfactory demonstration. (5) State reporting requirements. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 808 of 1275 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 should include a report of the periodic programmatic milestones to show progress in program implementation. The programmatic milestones with specific dates for achievement should be appropriate to the state measures included in the state plan submittal. As discussed in section VIII.F, for states using the state measures approach, the EPA is finalizing that at the end of each interim step period, 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 2 emission performance level identified in the state plan for the applicable interim step period versus the actual CO 2 emission performance achieved by the aggregate of affected EGUs. Beginning with the final period, the state must submit biannual 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 CO 2 emission performance rates or state CO 2 goal. If, at the time of the state report to the EPA, the state did not meet the programmatic milestones for the reporting period, or the performance check shows that actual CO 2 emission*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 809 of 1275 performance by affected EGUs exceeds the specified level of emission performance in the state plan submittal by 10 percent or more, the state must include in the state report a notification to the EPA that the backstop has been triggered and describe the steps taken by the state to inform the affected EGUs that the backstop has been triggered. In the event of such an exceedance under the state measures approach, the backstop federally enforceable emission standards for the EGUs must be

effective within 18 months of the deadline for the state reporting to the EPA on plan implementation and progress toward the meeting the CO 2 emission performance rates or state CO 2 emission goal. For example, if a state report due on July 1, 2025, shows that actual CO 2 emission performance by affected EGUs exceeds the specified level of emission performance for 2022- 2024 in the state plan by 10 percent or more, the backstop federally enforceable emission standards for affected EGUs must be effective as of January 1, 2027. (7) Supporting documentation.(a) Demonstration that each state measure is quantifiable, nonduplicative, permanent, verifiable and enforceable. A state using the state measures approach, in support of its plan, must also include in the supporting documentation of the state plan*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 810 of 1275

submittal the state measures 618 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. An example of a duplicative state measure 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

CO 2 emission rate of an affected EGU, except in the case of a multi-state plan where CO 2 emission performance is demonstrated jointly for all affected EGUs subject to the 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

618 “State measures” refer to measures that the state adopts and implements as a matter of state law. Such measures are enforceable only per applicable state law, and are not included in the federally enforceable state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 811 of 1275 to CAA section 111(d) requirements can satisfy other CAA program requirements (e.g., Regional Haze requirements, MATS etc.) and state requirements (e.g., RPS). 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 619 if it: (1) 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 affected entities responsible for compliance and liable for violations can be identified, (4) each compliance activity or measure is practically enforceable in accordance with EPA guidance on practical enforceability, 620 and the state maintains the ability

619 Under the state measures approach, state measures are enforceable only per applicable state law. 620 The EPA’s prior guidance on enforceability serves as the foundation for the types of measures that the EPA has found can be, as a practical matter, enforced. The EPA’s guidance on enforceability includes: (1) September 23, 1987, memorandum and accompanying implementing guidance, “Review of State Implementation Plans and Revisions for Enforceability and Legal Sufficiency,” (2) August 5, 2004, “Guidance on SIP Credits for Emission Reductions from Electric-Sector Energy Efficiency and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 812 of 1275 to enforce against violations and secure appropriate corrective

actions. 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 2 emission reductions sufficient to result in the necessary CO 2 emission performance

from affected EGUs for the CO 2 emission performance rates or

state CO 2 emission goal to be achieved. d. Legal basis for the components. (1) General legal basis. 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

Renewable Energy Measures,” and (3) July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable Energy Policies and Programs into State and Tribal Implementation Plans,” Appendix F.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 813 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 814 of 1275 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. 621 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

621 On the other hand, there are specific requirements in 110(a)(2) that are fundamental for SIPs, but would not make sense in the 111(d) context. For example, the specific requirement for an ambient air quality monitoring network in 110(a)(2)(B) is irrelevant in the 111(d) context. For a detailed discussion of the specific legal basis for each component, please see the Legal Memorandum for this final rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 815 of 1275 “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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 816 of 1275 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. (2) Legal issues with changes to affected EGUs. In the proposed rulemaking, the EPA took the position 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 requirements. 79 FR 34830, 34903–4. We noted that section 111(d) is silent as to this issue, which we took to grant us authority to provide a reasonable interpretation under*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 817 of 1275 the Supreme Court’s decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842–844 (1984). We stated two reasons to disallow existing sources to escape 111(d) through modification or reconstruction. First, if a source did so, that could prove disruptive to the state plan. Second, allowing sources to do so could provide them an incentive to do so that would be contrary to the purposes of 111(d). We then asked for comment on “whether this interpretation is supported by the statutory text and whether this interpretation is sensible policy and will further the goals of the statute.” With respect to our request for comments on whether our proposed interpretation is supported by the statutory text, we received comments arguing that it violates the statute. The commenters noted that section 111(a)(6) defines “existing source” as “any stationary source other than a new source,” and section 111(a)(2) defines “new source” to include stationary sources that are constructed or modified after “the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under [section 111] which will be applicable to such source.” The comments concluded from this that the two categories are mutually exclusive, regardless of section 111(d)’s silence on the issue. The comments also noted that section 111(d)(1) only allows states to impose*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 818 of 1275 standards of performance in 111(d) plans on existing sources “to which a standard of performance under [111] would apply if such existing source were a new source,” from which the comments inferred that states lacked authority under 111(d) to regulate sources that are regulated under 111(b). We do not completely agree with these comments, which “prove too much.” It is not the case that a source can never be both an existing source and a new source within the meaning of sections 111(a)(6) and 111(a)(2), respectively. First, a source that was a new source under 111(b) standards of performance for one pollutant can of course later become an existing source under 111(d) for another pollutant when the EPA promulgates 111(b) standards of performance and 111(d) emission guidelines for the second pollutant. Any other result would be illogical. Second, we have taken the position under section 129 (which has similar but not identical definitions) that a new source can subsequently become an existing source under revised 129(b) guidelines. E.g., 74 FR 51368, 51374-75 (Oct. 6, 2009). Thus, the comments’ “plain meaning” argument fails to take into

account context such as these. However, we do agree that, in the particular context here, i.e. when section 111(d) emission guidelines are initially promulgated for existing stationary sources in response to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 819 of 1275 corresponding section 111(b) standards of performance for the same pollutant, that the statute prohibits new sources (including under those particular 111(b) standards of performance from simultaneously being subject to state plans under those particular 111(d) emission guidelines. This interpretation gives meaning to the definition of “existing source” in section 111(a)(6) and is consistent with the definition of “new source” in section 111(a)(2). And, it is

consistent with the historical treatment of modified and reconstructed sources in the section 111 program. The EPA plans to address ways to minimize disruption to state plans if such a modification or reconstruction were to take place. We believe our final interpretation could reasonably be anticipated from our proposal notice. Although our notice proposed only a different interpretation of the statute, we did not indicate that the proposed interpretation was a settled matter (for example, based on previous EPA practice), and we invited comment on whether our interpretation was supported by the statute. Furthermore, we are basing our final position on the language of sections 111(a)(2) and 111(a)(6), which were quoted in our discussion of this exact issue in our proposal notice. 79 FR 34830, 34903/3. Thus, we gave adequate notice of the relevant provisions of the statute, and it could not be*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 820 of 1275 unfair surprise that sections 111(a)(2) and 111(a)(6) formed the basis of our ultimate position. Finally, there are a very limited number of potential interpretations of these provisions with respect to this issue; thus our final position could be reasonably anticipated. (3) Legal issues regarding design, equipment, work practice or operational standards. 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,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 821 of 1275 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 emissions standards under the emissions 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 cannot substitute for a mass-based limit on

the affected EGU. 622 This follows from the statute. First, section 111(h)(1)

622 In particular, a state may include in its 111(d) state plan an emission standard that is reflective of the CO 2 performance resulting from operational standards the state imposes on an affected EGU.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 822 of 1275 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 302(l) is similar to the definition of “emission limitation” (or “emission standard”) in 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.B.7.e(1), 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 823 of 1275 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) Legal basis for engagement with communities. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 824 of 1275 to the legal importance of adequate public participation in the state plan process, including public participation by 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 they have meaningfully engaged with affected 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. 3. Components of the federally approved state plan 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 Federal Register and provide an opportunity for notice and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 825 of 1275 comment. When a state plan submittal is approved by the EPA, the EPA will codify the approved 111(d) state plan in 40 CFR part 62. The following components of the state plan submittal will become the federally enforceable state 111(d) plan:

 Federally enforceable emission standards for affected EGUs

 Federally enforceable backstop of emission standards for

affected EGUs

 Implementing and enforcing measures for federally enforceable emission standards including EGU monitoring, recordkeeping and reporting requirements

 State recordkeeping and reporting requirements E. State Plan Submittal and Approval Process and Timing

1. Overview In this action the EPA is finalizing that state plan submittals are due on August 31, 2016, which is 13 months after finalization of the emission guidelines. The EPA recognizes that due to state legislative schedules and rulemaking processes, coordination needed among states involved in multi-state plans, coordination with third parties, and the complex technical work needed to develop a state plan, states may not be able to develop a final plan submittal by 13 months after the final rule. However, various states have existing CO 2 reduction programs in place, such as RE and demand-side EE measures, as*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 826 of 1275 well as state and regional programs designed to reduce CO 2 pollution from EGUs. Furthermore, state governments have already begun active discussions on how to address the final rule through policy forums, white papers and non-profit organizations. The EPA is also in the process of developing a federal plan that states may wish to use as a model rule. The EPA views these actions as positive steps that make the 13-month

timeline achievable. In order to address the concern that 13 months is not sufficient time for states to prepare and submit a final plan submittal and to allow consistent timelines for both a single state and multi-state approach to state plan submittals, the EPA is also finalizing a plan submittal process that provides additional time for states that need it to submit a final plan submittal to the EPA after August 31, 2016. This approach involves the option that we refer to as an initial submittal, followed by submittal of a final state plan submittalno later than August 31, 2018, for both single state and multistate plan submittals. During the initial outreach process as well as the public comment period on the proposed rule,

stakeholders commented that additional time was needed to accommodate, among other things, state legislative and rulemaking schedules, coordination among states involved in multi-state plans, coordination with third parties, and the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 827 of 1275 complex technical work needed to develop a state plan. The EPA recognizes that state administrative procedures can be lengthy, some states may need new legislative authority, and states planning to join in a multi-state plan will likely need more than 13 months to get necessary elements in place. Balanced against that concern, however, is the urgency of addressing CO 2 emissions and the fact that there are certain steps the EPA

believes states can take within 13 months to set themselves on a clear path to adoption of a final plan. 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 828 of 1275 plan, each of the required plan components (e.g., plan emission goals, program implementation milestones, emission performance checks, and reporting) would be designed and implemented by the participating states on a multi-state basis. The EPA is also finalizing two additional options it solicited comment on for multi-state plan submittals. First, states participating in a multi-state plan have the option of providing a single submittal — signed by authorized officials from each participating state — that addresses common plan elements. This option requires individual participating states to provide 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 829 of 1275 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. 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 (e.g. reciprocity agreements,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 830 of 1275 or state regulations) that allow affected EGUs to use emission allowances or RE/EE credits issued in one state for compliance

with an emission standard in another state. In order to avoid a multi-state plan becoming unapprovabledue to one state submitting an unapprovable portion of a multistate 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. 2. State plan submittal and timing The EPA 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. 623 The EPA is finalizing that each state must submit a final plan submittal to the EPA by August 31, 2016, (13 months after the final rule). The state may submit a

623 40 CFR 60.23(a)(1).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 831 of 1275 final plan submittal by this date, or seek an extension to submit a final plan by submitting an initial plan submittal. In this final rule the EPA is providing states with the option of up to a 2-year extension that will provide a total of 3 years for a state to develop and submit a final state plan to the EPA. To qualify for an extension of the August 31, 2016 deadline until August 31 2018, a state must submit an initial plan submittal by August 31, 2016, that documents the state’s plan for preparing a final plan submittal by 2018. The EPA is also finalizing that a state must submit one progress update by August 31, 2017. 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 plan 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 832 of 1275 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 or final plan submittal 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.7. 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. An initial plan submittal must include the components of a final plan submittal described in section VIII.D. Based on these components, potential justifications for seeking extensions*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 833 of 1275 include, among other things, 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, additional time needed for the development of RE or demand-side EE programs in low-income communities, and process and coordination necessary to develop a multi-state plan. 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, as part of its overall evaluation of whether the initial submittal justifies granting an extension for submission of the final plan, the EPA is requiring that states seeking an extension until 2018 must actively engage with communities with a potential likelihood of being adversely impacted by state plans, including low income communities and communities of color, throughout the state plan development process. In order to demonstrate to the EPA that states are actively engaging with affected communities, states must provide in their initial plan submittal a summary of how they have been engaging with community stakeholders and how they intend to meaningfully engage with community stakeholders during the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 834 of 1275 additional time (if an extension is granted) for development of the final plan. In particular, states must document meetings and interactions that they have had with affected communities. Furthermore, states in their initial plan submittal and 2017 update must show how they identified low income and communities of color that they are conducting meaningful community engagement with in the state plan development process. For some recommendations on the steps that states could take to engage communities in a meaningful way, the agency

recommends that states consult the EPA’s Interim Guidance on Considering Environmental Justice During the Development of an

Action . In this document, the EPA defines meaningful involvement, as ensuring that, “potentially affected community members have an appropriate opportunity to participate in decisions about a proposed activity that will affect their environment and/or health; the public’s contribution can influence the regulatory agency’s decision; the concerns of all participants involved will be considered in the decision-making process; and the decision-makers seek out and facilitate the involvement of those potentially affected.” 624 Additionally, this

624 Interim Guidance on Considering Environmental Justice During the Development of an Action.http://www.epa.gov/environmentaljustice/resources/policy/ejrulemaking.html. July 2010.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 835 of 1275 guidance document also encourages those writing rules consider the positive impacts that a rulemaking will have on communities). 625 Another resource that the EPA recommends that states consult when devising their state plans is the Considering Environmental Justice in Permitting resources available on the agency’s website. 626 Both of the resources discussed above will provide states with assistance on how to effectively engage communities in the rulemaking process. The EPA recommends that as part of their meaningful engagement with affected communities, that states work with affected communities to ensure that they have a clear understanding of the benefits and potential adverse impacts that a state plan might have on their communities and that there is a clear process for states to respond to input from communities. 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 August 31, 2016. 627 The EPA will publish a

notice in the Federal Register to notify the public of receipt

of such letters. If a state submits an acceptable initial plan submittal by

625 Ibid. 626 Considering Environmental Justice in Permitting.http://www.epa.gov/environmentaljustice/planej/permitting.html#actions. 627 40 CFR 60.23(b).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 836 of 1275 August 31, 2016, as specified in the plan guidelines, then the deadline extension for submitting a final plan submittal that the state requested will be deemed granted. If the EPA determines that the initial plan submittal does not meet the guidelines, the EPA will notify the state by letter, within 90 days, that the agency cannot approve the extension request based the state’s initial plan submittal as submitted. The EPA will notify a state by letter only if the initial plan submittal does not meet the guidelines. An extension for submitting a final plan submittal will be deemed granted if the EPA does not deny the extension request based on the initial plan submittal. The EPA has determined this approach is authorized by, and consistent with, 40 CFR 60.27(a) of the implementing regulations. In the proposal, EPA proposed an initial 13 month submittal, with a 1-year possible extension for states submitting plans on their own and a 2-year possible extension for states submitting as part of a multi-state region. The EPA received substantive comment on the achievability of these proposed deadlines for state plan. 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, if not*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 837 of 1275 impossible, 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 that a schedule shorter than 3 years will be extremely challenging for many — though not all - states. We note that the CAA provides multiple years for states to complete other types of plans, such as those under CAA section 110, that are similar (or less) in scope and complexity than these plans. In light of the comments received and in order to provide maximum flexibility to states while still taking timely action to reduce

CO 2 emissions, in this final rule the EPA is allowing for an extension until 2018 for both individual and multi-state plans. This 2-year extension is contingent upon a state submitting a detailed description of steps already taken, a detailed description of additional actions to be taken in order to meet the 2018 plan submittal date and the initial 2022 compliance deadline and a schedule for those actions. This 2-year extension is also contingent upon the state submitting an acceptable 2017 update by August 31, 2017 that documents the state’s continued progress towards meeting the 2018 submittal deadline. If the state does not submit an acceptable 2017 update by August 31, 2017, the state will have failed to meet the conditions for the 2-year extension and the EPA will develop a federal plan unless the state submits a final plan during this time. The EPA is also*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 838 of 1275 clarifying the requirements for approvable initial plan submittals and 2017 updates, which can be found in section

VIII.E.3. 3. Components of an initial state plan submittal and 2017 update and approvability criteria As noted, if a state is unable to prepare and submit a final plan submittal by August 31, 2016, the state must make an initial plan submittal by that date and may request up to a 2- year extension to submit a final plan. To be approved, the EPA is finalizing that the initial plan submittal must address all components of a final plan submittal, including identifying which components are not complete. For incomplete components, an approvable initial plan submittal must contain a comprehensive roadmap outlining the path to completion, including milestones

and dates. During the public comment period, multiple commenters stated that the proposed timeframe for states to submit an approvable initial state plan submittal was not achievable, citing, among other things, the amount of decisions needed to be made by a state or states, and that the EPA needed to clarify the requirements for submitting an approvable initial state plan submittal. Multiple commenters also expressed concern that the requirements for an approvable initial plan submittal required*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 839 of 1275 final decisions to be made by states, and that the initial plan submittal deadline was not enough time for states to make these decisions. In order to address the commenters’ concerns, the EPA is finalizing that in order to be approvable, an initial state plan submittal must address all components of a final plan submittal, including identifying which components are not complete, and include the following information:

 All components of a final plan, including which components are not complete.

 A justification for seeking an extension.

 A description of the plan approach (e.g., single or multi-state, CO 2 emission performance rates or state CO 2 rate or mass emission goal)

 A commitment to maintain existing measures that limit or

avoid CO 2 emissions (e.g., RE standards), at least until the final plan is approved.

 A 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.

 Demonstration of opportunity for public comment on submittal and response to significant comments, and meaningful engagement with affected communities likely to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 840 of 1275 be impacted by the state plan. As stated above, the EPA is finalizing that the initial plan submittal must address all components of a final plan submittal, including identifying which components are not complete. For incomplete components, an approvable initial plan submittal must contain a comprehensive roadmap outlining the path to completion, including milestones and dates. The EPA proposed that approvable justifications 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 acceptable justifications for seeking an extension beyond 2016. Although legislation and/or regulations do not need to be passed prior to the initial plan submittal in order to be granted an extension, the initial plan submittal must include any concrete steps the state has already taken on legislation and/or administrative rulemaking and detail what the remaining steps are in those processes before a final plan submittal can be submitted. The EPA also sought comment on other circumstances for which an extension of time would be appropriate, and also whether some*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 841 of 1275 justifications for extensions should not be permitted.

Commenters stated that states should be able to seek extensions whenever an extension can be reasonably justified, and that the EPA should take at face value states’ good faith efforts by accepting any state assertion that more time is needed to develop a plan unless there is clear evidence to the contrary. The EPA does not agree with the assertion that any reason provided by a state should automatically be deemed as an acceptable justification for being granted an extension. The EPA is not finalizing other justifications in this final rule, however, the EPA will evaluate the appropriateness of other justifications not listed here during review of the initial state plan submittals. For descriptions of plan approaches, states must include a basic outline of the approach used to meet the state’s CO 2 emission goals or the CO 2 emission performance rates. This should include, at a minimum, whether the state is choosing the option

of the CO 2 emission performance rates, a rate-based CO 2 goal, or

a mass-based CO 2 goal, and whether the state is pursuing a single-state or multi-state plan. Stakeholders commented that states will not be far enough along in the rule development process to have made these decisions. Commenters also stated that many state legislatures would need to pass legislation*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 842 of 1275 giving state environmental agencies legal authority and direction before they could begin to make decisions such as rate or mass-based approach or single or multi-state plan submittal. In order to address the commenters’ concerns, the EPA wishes to clarify that state approaches in the initial state plan submittal do not need to be final and/or formalized through a state legislature, and that states may opt to pursue more than one approach at the same time. In order to fulfill the requirement for a description of the plan approach, the initial plan submittal may include the various compliance options a state or group or states is exploring and a detailed schedule outlining the process for making decisions necessary to meet the deadline for final plan submittal. 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 back out of the multi-state plan and 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. Finalizing a 2-year extension that is available for any*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 843 of 1275 state, whether they are pursuing an individual state plan or a multi-state plan resolves the commenters’ concern aboutconflicting extension deadlines if states involved in a multistate effort decide not to pursue the multi-state approach. In order for a state’s initial plan submittal to be approvable, the EPA is finalizing that the initial submittal must contain a commitment to maintain existing measures, such as RE standards and demand-side EE programs, at least until the final plan is approved. The EPA could not in good faith agree with a state’s rationale for needing more time to develop a final state plan while at the same time the state was removing already in place measures that reduce CO 2 emissions from EGUs. An initial state plan submittal must also include a description of the progress a state has made in the development of a final plan submittal as well as a comprehensive roadmap for completing the plan. This includes a schedule with milestones and dates. The milestones should outline the state’s path to submitting a final plan by August 31, 2018. The EPA is finalizing the public comment requirements that were outlined in the proposal for initial plan submittals. Prior to submittal to the EPA, the state must provide an opportunity for public comment on a substantial draft of its initial plan submittal. This public comment opportunity will not be governed*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 844 of 1275 by the procedural requirements of the implementing regulations that apply to the state’s adoption of a final plan, such as the requirement that the state hold a public hearing. 40 CFR 60.23(c)-(f). An initial plan submittal might not include any legally enforceable provisions that the state would have adopted through its administrative or legislative processes, which generally provide for public input. Therefore, to ensure that the public has an opportunity to understand and inform the initial plan submittal, the final rule requires that prior to submittal on August 31, 2016, the state must have provided a reasonable opportunity for public comment on a substantial draft of the initial plan submittal, with notice to the EPA of that comment period. The EPA can use this comment opportunity to advise the state whether it is on track to submit an approvable initial plan submittal. The comment period on the initial plan 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 for this final rule. When the state submits its initial plan submittal, it must provide the EPA with a response to any*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 845 of 1275 significant comments it received on issues relating to the approvability of the initial plan so that the EPA can fully assess whether it is approvable. For states participating in a multi-state program, the initial plan submittal must include the elements described above as well as any executed agreements among the participating states and a road map for both design of the multi-state program and its implementation at the state level. A multi-state initial plan submittal should also address situations where states may join together on only certain elements, such as RE, or standards

on subsets of EGUs. In this final rule, the EPA is allowing states up to 3 years to submit a final plan. This is contingent upon submitting an acceptable initial plan submittal and 2017 update. The 2017 updates will ensure that a state is making continuous progress on its initial plan and that a state is on track to meet the final plan submittal deadline of August 31, 2018. The EPA is requiring that the 2017 update must contain the following components:

 A summary of the status of each component of the final plan, including an update from the 2016 initial plan submittal and a list of which components are not complete.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 846 of 1275

 A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), including draft or proposed legislation and/or regulations.

 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 if 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 summary of all components of a final plan, including a progress update on any incomplete components from the initial plan submittal, and a list of which components are still not complete. This progress update must

demonstrate that state has met the milestones and dates it outlined in its initial plan submittal. If a state has not met a milestone and date that it set in the initial plan submittal, or is not on pace to meet a future date, the state may revise its schedule in the 2017 update, provided that the schedule meets the 2018 deadline for final plan submittal. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 847 of 1275 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 clarified that proposed or passed legislation or regulations are not required in the initial plan submittal. While a state may pursue multiple types of state plans in the initial plan 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. Finally, the EPA is requiring that the 2017 update include an updated comprehensive roadmap with a schedule and milestones for completing the plan. Similar to the requirement that the 2017 update must include all components of a final plan, the update must include a demonstration that the state met the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 848 of 1275 milestones for submitting a final plan that were outlined in the initial plan submittal. For any milestones that were not met, the state must provide a justification for not meeting the milestone and an updated schedule that demonstrates that the state is still on pace to meet the 2018 final plan submittal

deadline. The EPA will assess a state’s 2017 update and, similar to the process for the initial plan submittal, notify the state within 90 days if the EPA determines that the state is not likely or able to meet the 2018 final plan submittal deadline. In the event that the EPA makes this determination for a state, the EPA will begin the federal plan development process to enforce and implement in the state. 4. Process for EPA review of state plans Our proposal laid out the basic steps for 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 111d, some additional procedural elements we believe will be helpful to states, stakeholders and the EPA moving forward.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 849 of 1275 Following the August 31, 2016 deadline for state plan submittals, the EPA will review plan submittals for approvability. For a state that submits an initial plan submittal by August 31, 2016, and requests an extension of the deadline for the submission of a final state plan submittal, the EPA will determine if the initial plan submittal meets the minimum requirements for an initial plan submittal. If the initial plan 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 August 31, 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, similar to that used for approving SIP submittals under section 110 of the CAA. The implementing regulations currently provide for the EPA to act on a final plan within 4 months after the deadline for submission, which is consistent with versions of section 110 prior to the 1990 Amendments to the CAA. 40 CFR 60.27(b). To be consistent with the current version of section 110, the EPA intends to adopt a timeline of 12 months to review final plan submittals upon receipt of complete submittals, as is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 850 of 1275 generally consistent with the timing requirements of section 110 with respect to complete SIP submittals. Such a timeline would also provide the EPA with adequate time for review and rulemaking procedures, and ensuring an opportunity for public notice and opportunity for comment. We note, however, that we did not propose this timeline for review and action on state plans in our proposal, and, in particular, starting the 12 month review period from the date of receipt of a complete

submission. 628 Therefore, we intend to propose the appropriate revisions to the implementing regulations as part of the upcoming federal plan proposal for section 111(d). In addition, while the CPP 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 in 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), and the EPA

628 The EPA proposed 12 months after the date required for submission of a plan or plan revision to approve or disapprove such plan or revision or each portion thereof.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 851 of 1275 believes this requirement is appropriate to establish under section 111(d)’s direction of 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 intends to do so as part of the upcoming Federal Plan proposal for section 111(d). The EPA notes the components of state plans as laid out in section VIII.D and the final rule are 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 allow 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 will be further explained in the upcoming 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 852 of 1275 111(d) plans. The input the agency got in response to the proposal for these guidelines indicated that the flexibility provided by these mechanisms could be useful getting state plans in place. So, the EPA expects to propose 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. Deferring 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. 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.

5. Failure to submit a plan*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 853 of 1275 If a state fails to 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 Federal Register notice informing the public of its finding of failure to submit. Upon a finding of failure to submit for a state, a statutory clock will run requiring the EPA to promulgate a federal plan for such state no later than 2 years after the EPA makes the finding unless the state submits, and the EPA approves, a state plan during this time.

6. State plan modifications a. Modifications to an approved state plan. 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 measures with new measures. The EPA received broad support for allowing states to submit modifications to approved state plans. In this rulemaking, the EPA is finalizing that a state or states may revise its state 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 compliance timeframes in this final rule and flexibility provided to states in developing*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 854 of 1275 state plans will lessen the need for modifications to approved state plans. The EPA solicited comment on whether, for new projections of emission performance, 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.

b. Modifications to interim and final CO 2 emission goals. As discussed in section VII, the final rule specifies that the

state interim and final CO 2 emission goals may be adjusted to address inventory changes within a state’s fleet. If these*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 855 of 1275 changes occur before a state submits its initial or final plan,

the state should indicate in its submittal the circumstance that necessitates the goal adjustment and the revised interim or

final CO 2 emission goal. If the circumstances occur after a state has an approved plan, a state must submit a modification to its approved plan. The plan revision submittal must indicate the circumstance that necessitates the goal adjustment, the revised interim and/or final CO 2 emission goal, and the adjustments to the enforceable measures in the plan. As discussed in more detail in section VIII.H, the final rule has several measures to ensure reliability. One such measure is that if a state cannot address a reliability issue within the boundaries of an approved state plan and the built-in reliability contingencies are not adequate to address reliability related issues that arise, the state can submit a request to the EPA to amend the timeframe over which reductions must be made in its plan. See section VIII.H for a more detailed

discussion of this issue. 7. Plan templates and electronic submittal The EPA is finalizing the requirement for states to electronically submit a negative declaration, state plan submittals, including any supporting materials that are part of a state plan submittal and any state reports required by the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 856 of 1275 state plan. The rule provides that files that are submitted to the EPA in an electronic format may be maintained by states in an electronic format. The submission of the information by the

authorized official must be in a non-editable format. In addition to the non-editable version, the EPA is also requiring that all plan components designated as federally enforceable must be submitted in an editable version as well, as discussed

below. a. Submittal of an editable version of federally enforceable plan components. 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 submittal 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. Plan revisions. Following initial plan approval, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 857 of 1275 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. 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 DataExchange (CDX) (http://www.epa.gov/cdx/). The EPA will preregister authorized officials and plan preparers in CDX. Seesection VIII.E.2 for additional information on the preregistration process for authorized officials and plan preparers. Detailed instructions for accessing CDX and SPeCS will be outlined in the “111(d) SPeCS User Guide: How to submit state 111(d) plan material to EPA” which will be available on

the EPA’s Clean Power Plan Toolbox for States. The EPA will provide SPeCS training for states prior to the state plan

submittal due date.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 858 of 1275 Once in CDX, SPeCS can be selected from the Active Program Service List. The preparer (e.g., state representative compiling a state plan submittal) assembles the submission package. The preparer can upload files and complete electronic forms. However, the preparer may not formally submit and sign packages. Only registered authorized officials may submit and sign for the state with the exception of draft submittals. The EPA’s intent is to allow submittal of draft plans or parts of plans for early EPA review prior to formal submission by the authorized official and will allow preparers, as well as authorized officials, to

submit draft documents. The authorized official will be able to assemble submission packages and will be able to modify submission packages that a preparer has assembled. The key difference between the preparer and the authorized official is that the authorized official can submit and sign a package for formal EPA review using an electronic signature. In the case of a multi-state plan, each participating state’s authorized official must provide an electronic signature. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 859 of 1275 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: http://www.epa.gov/cromerr/. If a plan submittal includes confidential business information (CBI) it will also be required to be electronically submitted. Although the likelihood that CBI will be submitted as part of the state plan submittal is low, the EPA intends to ensure that the system is capable of supporting submittal of all the types of information that may be associated with a state plan. Material claimed as CBI will be flagged by the state in the electronic system as such, then uploaded and stored separately in the encrypted CROMMERR archive. Authorized staff will retrieve CBI for storage and management at the EPA’s CBI Office.

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 (e.g. paper submittal). Requiring electronic submittal is in keeping with current*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 860 of 1275 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. In the proposal, the EPA requested comment on the creation of templates for initial and final state plan submittals. Multiple commenters requested the EPA provide state plan templates. One commenter requested templates for different plan*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 861 of 1275 designs (e.g. a mass-based trading framework, a rate-based trading framework, multi-state compliance and a utility-based portfolio approach) and for specific plan components (e.g. how to incorporate a state RE standard and an EE program into a state plan, how to assess the emission reductions delivered by RE and EE). The EPA has decided not to develop templates for state plan submittals at this time given the broad range ofapproaches states may take in preparing individual or multistate plans. However, the EPA does believe that states may use the Federal Plan as a template when preparing state plan

submittals. The EPA will continue extensive outreach to states and work closely with states on the need for additional tools and guidance to facilitate the development of approvable state plans. 8. Legal issues regarding state plan process 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. 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 111(d) state plans, and if so, precisely*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 862 of 1275 how those 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 being issued

concurrent with this final rule. In this section we discuss the legal basis for procedures that the EPA is finalizing in this action: initial plan submittals, extensions, and plan revisions. First, we generally discuss the ambiguous word “similar.” “Similar” does not have an identical meaning as the word “same.” Webster’s Third New International Dictionary defines “similar” as “having characteristics in common, very much alike” or “alike

in substance or essentials.” Webster’s Third New International Dictionary 2120 (1993). On the other hand, “same” is defined as “resembling in every way, not different in relevant essentials,” “conforming in every respect,” or “corresponding so closely as to be indistinguishable.” Id. at 2007. Thus, had Congress intended that the procedures for section 111(d) plans be indistinguishable from those in section 110, Congress knew how to say so. See, e.g. , 36 U.S.C. § 2352(b)(2)(B) (“same procedures”). And had Congress intended that the procedures for section 111(d) plans be as close as possible to those in section 110, Congress knew how to say that. See, e.g., 38 U.S.C. § 4325(c) (agency “shall ensure, to the maximum extent practicable, that the procedures are similar to”*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 863 of 1275 certain other procedures). Therefore, Congress must have intended to give the EPA leeway to create procedures for section 111(d) state plans that somewhat vary from those in section 110, so long as the section 111(d) procedures are reasonably tied to the purpose and text of section 111(d). In other words, “similar” creates a gap in the statute that the EPA may reasonably fill. a. Initial plan submittals and extensions. Section 110 does not provide for initial plan submittals. As explained above, though, we are not bound under section 111(d)(1) to follow exactly the same procedures. Initial plan submittals in this instance are a reasonable gap-filling device. As explained in our proposal, certain aspects of section 111(d) plan development for these particular guidelines warrant our creation of this device. With respect to the timing of initial plan submittals, final submittals, and extensions, we note that 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. Section 110(a)(1) does not provide any particular factors for the Administrator to consider in prescribing a shorter period. Thus, the EPA’s prescription of a shorter period for either an initial plan submittal or a final plan submittal*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 864 of 1275 is consistent with the discretion granted in section 110(a)(1). We also note that section 110(b) provides for extensions of up to 2 years for plans to implement secondary NAAQS, that other provisions in part D provide for extensions of due dates of attainment plans in certain circumstances, and that the section 111(d) implementing regulations provide for extensions generally. We conclude, in view of the above discussion of “similar,” that the device of initial plan submittals and extensions of due dates as proposed is a reasonable procedure that, while not identical to the procedures in section 110, is

still similar. Some commenters argued that the 1-year period for initial plan submittals and, even assuming an extension, the additional 1- to 2-year period for final submittals were unreasonable, 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 plan 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 865 of 1275 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. While developing attainment plans may not require states to seek additional legislative authority, 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),*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 866 of 1275 control measures for those sources (including individualized control measures for the larger sources), and modelled demonstrations of attainment (which in some instances requires photochemical grid modeling). Thus, it is reasonable to have the same timeline for these section 111(d) plans as Congress generally provided for attainment plans in section 172(b). b. State plan modifications. 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. It is reasonable, at a minimum, that the state*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 867 of 1275 plan as revised should continue to provide for implementation and enforcement of the standards of performance, and to achieve

the CO 2 emission performance rates or state CO 2 emission performance goal. This is analogous to the substantive requirements of section 110(l), which as explained above for section 110(a)(2), we may consider in determining how to reasonably fill statutory gaps for section 111(d) plans. In our proposal, we proposed 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 2 emission performance rates

or state CO 2 emission performance goal. We proposed that this demonstration might be simple for minor revisions, but for major revisions a more complete demonstration may be required. We are finalizing this proposal. As legal basis for this position, we note that a demonstration is necessary to show that a state plan provides for implementation of standards of performance that

achieve the CO 2 emission performance rates or state CO 2 emission performance goal, and as explained above we can reasonably require the same of revisions. It is also reasonable to tailor the requirements of the demonstration to the magnitude of the revision. The EPA has*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 868 of 1275 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 performance emission 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 869 of 1275 believe that our proposal was unclear as to this point and we agree that the same standard for revisions should be the same as for submittals. We have finalized this position.

F. State Plan Performance Demonstrations This section describes state plan requirements related to compliance periods, monitoring and reporting for affected EGUs; plan performance demonstrations; and consequences if the CO 2 emission performance rates or state CO 2 emission goals are not

met. 1. Compliance periods, monitoring and reporting requirements for

affected EGUs 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 (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). If a backstop is triggered for a state measures plan, the schedule of compliance for the federally enforceable emission standards must begin no later than 18 months after the backstop is triggered and end at the end of the same compliance period. For example, if a backstop is triggered on July 1, 2025, the compliance*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 870 of 1275 period for the backstop emission standards must begin no later than January 1, 2027, and end on December 31, 2027. The next compliance period for the backstop emission standards would be January 1, 2028-December 31, 2029. 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 indicated above, which respond to the comments by applying to both rate- and mass-based*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 871 of 1275 programs, providing compliance periods longer than one 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 and provide a basis for emissions reductions that are more realistic than short term averaging might otherwise demonstrate.

The EPA finalizes that states can choose to set shorter compliance periods for their emission standards but no longer than the compliance periods the EPA is finalizing in this rulemaking. 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.” See e.g., June 13, 1989 “Guidance on Limiting Potential to Emit in New Source Permitting” and January 25, 1995 “Guidance on Enforceability Requirements for Limiting Potential to Emit through SIP and §112 Rules and General Permits.” 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 2 is long-lived in the atmosphere,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 872 of 1275 and this rulemaking is focused on performance standards related to those long-term impacts. The distinction between these unique characteristics and the EPA’s long-standing practice regarding compliance periods is bolstered by the EPA guidance on appropriate averaging periods for emission limitations in NAAQS implementation. For example, the EPA guidance has stated that in implementation of the ozone standards, which have a short averaging period, the averaging period for VOC emission limitations should be correspondingly short. See 51 FR 43857. A longer averaging period for VOC emission limitations can allow spikes in emissions that adversely impact ambient air and violate the short term ozone standards. This is precisely theopposite of the unique characteristics cited above: the longlived persistence of CO 2 in the stratosphere and the intent of these guidelines to address the long-term impacts. State plans must contain requirements for tracking and reporting actual plan performance during implementation, which includes reporting of CO 2 emissions from affected EGUs. Affected EGUs must comply with emissions monitoring and reporting requirements that are largely incorporated from 40 CFR part 75 monitoring and reporting requirements. The majority of affected EGUs are already familiar with the reporting requirements of part 75, and because of this, the EPA has chosen to streamline*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 873 of 1275 the applicable reporting requirements for sources under the state plans in the final rule. States must require all affected EGUs to monitor and report hourly CO 2 emissions and net energy output (including total net MWh output that is comprised of generation, and where applicable, useful thermal output converted to net MWhs) to the EPA on a quarterly basis in accordance with 40 CFR part 75. Note that this requirement applies for all types of state plans, regardless of whether the state chooses the option of the CO 2 emission performance rates, a

state rate-based CO 2 emission goal, or a state mass-based CO 2 emission goal. 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 to 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 874 of 1275 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 2 emissions and net hourly electric output under 40 CFR part 75, and report the data using the EPA's Emission Collection and Monitoring Plan System (ECMPS) assuring a more uniform monitoring and reporting process for all EGUs. The EPA believes that the final monitoring and reporting requirements (via ECMPS)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 875 of 1275 address the issue of duplicative requirements and alleviate concern about lost flexibilty raised by commenters. 2. Plan performance demonstrations 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 2 emission performance rates or state CO 2 emission goal during a performance period. As discussed previously in section VII, the agency is finalizing CO 2 emission performance rates or state-specific CO 2 emission goals that represent emission levels to be achieved by 2030 and emission levels to be achieved on average over the 2022-2029 interim period, and over three interim steps of 2022- 2024, 2025-2027 and 2028-2029. The EPA recognizes the importance of ensuring that, during the 8-year interim period (2022-2029) for the interim performance rates or interim state goal, a state is making steady progress toward achieving the required level of emission performance. For both emission standards plans and state measures plans, the final rule requires periodic checks on overall emission performance leading to corrective measures or implementation of the backstop, if necessary, as described in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 876 of 1275

section VIII.F.3 below. States must demonstrate that the interim steps were achieved, on average during the interim step periods, at the end of each interim step. In 2032 and every 2 years thereafter, states must demonstrate that affected EGUs achieved the final performance rates or state goal on average during each 2-year reporting period (i.e., 2030-31, 2032-33, 2034-2035 etc.). The multi-year performance periods for measuring actual plan performance against the performance rates or state goals allow states some flexibility that accounts for seasonal operation of affected EGUs, and inclusion of RE and demand-side EE efforts. For a rate-based plan, emission performance is an average

CO 2 emission rate for affected EGUs representing cumulative CO 2 emissions for affected EGUs over the course of each reporting period divided by cumulative MWh energy output 629 from affected EGUs over the reporting period, with rate adjustments for qualifying measures, such as RE and demand-side EE measures. For a mass-based plan, emission performance is total tons of CO 2 emitted by affected EGUs over the reporting period. For emission standards plans, as discussed in section VIII.D, the state must submit a report to the EPA of the

629 For EGUs that produce both electric energy output and otheruseful energy output, there would also be a credit for nonelectric output, expressed in MWh.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 877 of 1275 emissions performance comparison for each reporting period no later than the July 1 following the end of each reporting period (i.e., by July 1, 2025; July 1, 2028; July 1, 2030; July 1, 2032; and so on). The EPA notes that for certain types of emission standards plans, with mass-based emission standards in the form of anemission budget trading program, achievement of a state’s massbased CO 2 goal (including interim step goals and final goal) will be assessed by the EPA based on compliance by affected EGUs with their emission standards under the program, rather than CO 2 emissions during a specific interim step period or final period. As discussed in section VIII.C.3.b.(2)(a), this approach is limited to plans with emission budget trading programs where compliance by affected EGUs with the emission standards will ensure that, on a cumulative basis, the state interim and final

mass-based CO 2 goals are achieved. 630 This approach allows for CO 2 allowance banking across plan performance periods, including from the interim period to the final period. As a result, CO 2emissions by affected EGUs could differ from the state massbased CO 2 goal during an individual plan performance period, but

630 Emission budget trading programs in such plans establish CO 2 emission budgets equal to or less than the state mass CO 2 goal, as specified for the interim plan performance period (including specified levels in interim steps 1 through 3) and the final two-year plan performance periods.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 878 of 1275

on a cumulative basis CO 2 emissions from affected EGUs would not

exceed what is allowable if the interim and final CO 2 goals are

achieved. 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 milestones identified in the state plan submittal. The annual report that follows the end of each reporting period (i.e., 2022-2024, 2025-2027, and 2028- 2029) must also include an emissions performance comparison for the reporting period, as described above for the emissions standards plan. Beginning with the final period of 2030 and onward, states using a state measures plan must submit a biannual report no later than July 1 following the end of each reporting period with an emission performance comparison for each reporting period, consistent with the reporting requirements for emission standards plans. In the June 2014 proposal, the EPA proposed that a state report is due to the EPA no later than the July 1 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 879 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 880 of 1275 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. 3. Consequences if actual emission performance does not meet the

CO 2 emission performance rates or state CO 2 emission goal 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 881 of 1275

CO 2 emission performance rates or state goals in 2022–2029, or does not meet the applicable final CO 2 emission performance rates

or state CO 2 emission goal in 2030–2031 or later. For emission standards plans, the final rule specifies that corrective measures must be enacted once triggered. 631 The determination that a state 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, or the CO 2 emission performance rates, will be made through the actual performance checks to be included in state reports of performance data described in

section VIII.D.2.a above. For states using the emission standard approach, if actual

CO 2 emission performance by affected EGUs exceeds the specified level of emission performance in the state plan by 10 percent or more during any of the specified interim step reporting periods or during a final plan reporting period (after 2030), the state report must include a notification to the EPA that corrective

631 As in the proposal preamble, the EPA continues to note that some types of plans are “self-correcting” in that they inherently would assure interim performance and full achievement of the state plan’s required level of emission performance through requirements that are enforceable against affected EGUs. One example is a state plan with a rate-based emission performance level that requires affected EGUs collectively to meet an emission rate consistent with the state’s required emission performance level, and allows EGUs to comply through an emission trading program. Such plans presumably would not trigger or require corrective measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 882 of 1275 measures have been triggered. If, in the event of such an exceedance, the EPA determines that corrective measures have been triggered and the state has failed to notify the EPA, the

EPA will inform the affected EGUs that corrective measures have been triggered. After an exceedance by 10 percent or more, 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 2 emission performance rates or state CO 2 emission goal and achieve additional emission reductions to offset any emission performance deficiency that occurred during a performance period. The state must submit the revised plan to the EPA within 24 months after submitting the state report indicating the exceedance. The EPA will then act on the plan revision within 12 months, consistent with other plan revisions and with the timing for final plan submittals originally submitted by states. For states using the state measures approach, the EPA is finalizing the backstop requirement as described in section VIII.C.4.b 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–*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 883 of 1275 2031 or later, or the CO 2 emission performance rates, is based on checks that must be included in state reports that must be submitted annually during the interim period and biannually during the final period. The state must report any failure to meet programmatic milestones during the interim period. In addition, the state must report actual performance checks, similar to the requirements discussed above for emission standards plans. If, at the time of the state report to the EPA, the state did not meet the programmatic milestones for the reporting period, or the performance check shows that actual CO 2 emission performance by affected EGUs exceeds the specified level of emission performance in the state plan submittal by 10 percent or more, the state must include in the state report a notification to the EPA that the backstop has been triggered. If, in the event of such an exceedance, the EPA determines that the backstop has been triggered and the state has failed to notify the EPA, the EPA will inform the affected EGUs that the backstop has been triggered. Multiple commenters requested that corrective measures not be required in the case of a catastrophic, uncontrollable event. We recognize the possibility that an un-anticipatable system emergency could cause a severe stress on the electricity system for a length of time such that the multi-year requirements in a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 884 of 1275 state plan may not be achievable by given EGUs without posing an otherwise unmanageable risk to reliability. We are finalizing a reliability safety valve that will allow a state to modify the emission standards for such EGUs for a maximum of 90 days. The reliability safety valve will allow such EGUs to operate under

the modified emission standards rather than the emission standards specified in the relevant state plan for that time period (including 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), while still requiring the CO 2 emission performance

rates or the state CO 2 emission goal to be met. While use of the reliability safety valve would preclude an applicable event from triggering corrective measures or a backstop during the safety valve period, the state must still make up for any emission reductions that were lost during the safety valve period. See section VIII.H.2.e of this preamble. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 885 of 1275 plan to trigger corrective measures. Some commenters supported the proposed trigger (actual emission performance that is not within 10 percent of the projected performance) that we are finalizing, while some recommended a lower trigger and others recommended a trigger higher than 10 percent exceedance. We have decided to finalize the trigger at 10 percent exceedance because we view 10 percent as both low enough to ensure that states that need corrective measures implement them before they exceed their specified level of emission performance to a degree that might be irreversible, and high enough that corrective measures are not triggered by fluctuations in emissions that do not indicate that a state may not be able to achieve its projected 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 2 emission performance rates or state CO 2 emission goal during a performance period, the EPA would require the state to cure the deficiency with a new plan within a specified period of time. If the state still lacked an approved plan by the end of that time period, the EPA would have the authority to promulgate a federal plan under CAA section 111(d)(2)(A). 79 FR 34830, 34908/1-2 (June 18, 2014).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 886 of 1275 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 plans to propose these revisions to the 111(d) implementing regulations in the forthcoming 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. Legal basis for corrective measures. 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.”

Id. at 13568. The fourth principle, accountability, means (among other things) that “the SIP must contain means ... to track emission changes at sources and provide for corrective action if emissions reductions are not achieved according to the plan.” In the General Preamble, we noted that Part D of Title I explicitly provided for this in certain instances by requiring milestones and contingency measures.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 887 of 1275 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, e.g., section 179(d). This is analogous to what we are requiring for corrective measures. Thus, part D contingency measures are unlike the corrective measures in this

rule. However, the requirement to revise an attainment plan in response to failure to attain differs from the corrective measures in these guidelines in one important respect. Under these guidelines, the corrective measures must make up the difference by which the plan fell short of the goal. There is no*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 888 of 1275 corresponding requirement in attainment planning to increase the stringency of the plan by an amount that somehow matches an amount by which the area failed to attain; instead the revised plan must demonstrate attainment, 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 2 , it is possible to remedy this failure by requiring the plan to be revised in such a way that the standards of performance in the revised plan will reflect the BSER over the cumulative plan period, and this can be done by requiring the revised plan to make up the shortfall from the previous period. In short, the flexibility that these guidelines provide should not come at the cost of allowing the standards of performance to reflect less than the BSER over the long run. 632

632 Similar considerations apply to the requirement under the state measures approach to revise the plan to make up the shortfall.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 889 of 1275 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 certain types of emission standards plans to fill this gap with corrective measures. There are two ways an emission standards plan can provide for implementation of standards of performance that

achieve the CO 2 emission performance rates or requisite state CO 2 emission performance goal. First, the state can set emission standards that necessarily achieve the performance rates or goal, even if the affected EGUs in the future vary in their relative amounts of electricity generated. Second, the state can

set emission standards that are demonstrated to achieve the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 890 of 1275 performance rates or goal based on assumptions about the relative amounts of electricity generated, but which may turn out to not actually achieve the goal. This is analogous to an attainment plan that demonstrated attainment by the applicable attainment date, but due to unpredicted economic changes actually failed to attain. In this second case, the EPA interprets the ambiguous language “provide for implementation . . . of standards of performance” in the context of achieving the performance rate or emissions goal, to mean that at the time the plan is submitted it must contain some mechanism to check the progress of the plan and correct course. The EPA has determined that, for this particular rule, the minimum mechanism is the set of milestones and provisions for corrective measures specified

in this rule. 4. Out-year requirements: Maintaining or improving the level of emission performance required by the emission guidelines The agency is determining CO 2 emission performance rates and

state CO 2 emission goals for affected EGU emission performance based on application of the BSER during specified time periods. This raises the question of whether affected EGU emission performance should be maintained at the 2030 level – or instead should be further improved - once the final CO 2 emission performance rate or state CO 2 emission goal is met in 2030. This*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 891 of 1275 involves questions of performance rate and goal-setting as well as questions about state planning. The EPA believes 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 that do not expire. Therefore, the EPA is finalizing that the level of emission performance for affected EGUs represented by

the final CO 2 emission performance rates or state CO 2 emission goal should continue to be maintained in the years after 2030. 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 892 of 1275 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. Legal basis for maintaining emission performance. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 893 of 1275 “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). Wealso requested comment on whether “we should establish BSERbased state performance goals that extend further into the future (e.g. beyond the proposed planning period), and if so, what those levels of improved performance should be.” Id. at 34908/3. 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,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 894 of 1275 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 relaxes 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 2 emission performance rates or state CO 2 emission goals are achieved in 2030. This is consistent with our past practice for section 111(d) rules, which do not contain any provision that in the future removes or relaxes the promulgated guidelines. In light of the persistence of CO 2 as a pollutant and its long-term impacts, it is particularly critical in these guidelines to explicitly provide for continuing emission reductions. G. Considerations for Incorporating CO 2 Emission Reduction

Measures in State Plans 1. Accounting for emission reduction measures in state plans

This section describes how measures that reduce CO 2 emissions from affected EGUs may be counted in state plans. This includes accounting for measures that occur directly at affected EGUs, as well as measures that provide substitute generation for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 895 of 1275 affected EGUs or avoid the need for generation from affected EGUs. This latter category of measures may be used to adjust the

CO 2 emission rate of an affected EGU under a rate-based state plan. This adjustment may occur when an affected EGU is demonstrating compliance with a rate-based emission standard, or when a state is demonstrating achievement of the CO 2 emission performance rates or applicable state CO 2 emission goal in the emission guidelines. 633 It should be noted that under a mass-based plan, measures that provide substitute generation for affected EGUs or avoid the need for generation from affected EGUs are automatically accounted for to the extent that these measures reduce reported

CO 2 emissions from affected EGUs. Unlike under a rate-based plan, no additional accounting is necessary in order to recognize

these emission reductions.

Section VIII.G.1.a below addresses how emission reduction measures that occur at affected EGUs are counted in state plans.

This includes measures that result in CO 2 emissions reductions that are automatically accounted for in reported CO 2 emissions

and CO 2 emission rates for affected EGUs, as well as other

633 Under a state measures plan, as described in section VIII.C.4, a state may adjust the reported CO 2 emission rate of affected EGUs when demonstrating achievement of the CO 2 emission performance rates or applicable state CO 2 emission goal in the emission guidelines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 896 of 1275 emission reduction measures, in particular the use of CCS, CCU and biomass, that require additional accounting and reporting.

Section VIII.G.1.b below addresses how emission reduction measures that provide substitute generation for affected EGUs or avoid the need for generation from affected EGUs are counted in rate-based state plans. This section describes the basic accounting method for adjusting a CO 2 emission rate. The section also describes general eligibility requirements for measures that may be used for adjusting a CO 2 emission rate, such as the requirement that the emissions-reducing action occur after 2012, which is necessary to maintain the integrity of the performance rates and state emission goals established in the guidelines. In addition, this section clarifies the treatment of the following measures that may be used to adjust a CO 2 emission rate:

 RE, including electric generating technologies using RE resources, such as wind, solar, geothermal, hydropower, biomass and wave and tidal power. Additional requirements are specified for the following RE resources:

o hydropower;

o biomass; and

o waste-to-energy

 Demand-side EE

 Demand-side management (DSM)*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 897 of 1275

 Transmission and distribution (T&D) measures that increase T&D efficiency or reduce electricity end-use

 Energy storage

 Water system efficiency

 CHP

 Waste heat to power (WHP)

 Nuclear power Where applicable, this section includes additional eligibility requirements and accounting methods that apply to specific categories of measures, in order to determine the MWh of electricity generation or electricity savings that may be used to adjust a CO 2 emission rate. Section VIII.G.1.c addresses measures that may not be used to adjust the CO 2 emission rate of an affected EGU in a state plan, and explains the basis for this exclusion. This includes new, modified, and reconstructed fossil fuel-fired EGUs subject to emission standards under CAA section 111(b) and other existing and new fossil fuel-fired EGUs that are not subject to emission standards under CAA section 111(b). Section VIII.G.1.d

addresses measures that reduce CO 2 emissions outside the electric power sector. Such measures may not be counted under either a rate-based or mass-based state plan. The categories of measures included in sections VIII.G.1.a-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 898 of 1275 b represent a wide range of actions that may be taken to reduce

CO 2 emissions at an affected EGU, as well as actions taken in the generation, transmission, distribution, and end-use of electricity that reduce CO 2 emissions from affected EGUs. The EPA anticipates that the categories described, including their eligibility requirements and accounting methods, represent the broad range of actions that states may seek to include in their state plans to meet the emission guidelines. However, it does not necessarily represent an exclusive list. A measure that is not specifically discussed in this section may be included in a state plan, provided the measure meets all requirements specified in the emission guidelines. This includes the requirements that a measure be quantifiable and verifiable, as

described in section VIII.D.2.b.

a. Affected EGU actions that reduce CO 2 emissions. Multiple actions may be taken at affected EGUs that reduce CO 2 emissions from an affected EGU and/or improve its CO 2 emission rate. This section describes this range of emission reduction actions and their accounting treatment in a state plan. Some of these actions do not necessitate additional accounting, monitoring or reporting requirements. Such actions are discussed in section VIII.G.1.a.(1) below, and include heat rate improvements, fuel switching from one fossil fuel to another, integration of RE*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 899 of 1275 into EGU operations, and CHP expansion or retrofit. Other actions, however, do necessitate additional accounting, monitoring, or reporting requirements. These include use of CCS, CCU and biomass, as discussed in section VIII.G.1.a.(2) below. (1) Actions without additional accounting and reporting requirements. Many actions will reduce the reported CO 2 emissions

or CO 2 emission rate of an affected EGU, without the need for additional accounting or monitoring and reporting requirements beyond the required CEMS tracking of actual stack CO 2 emissions and tracking of actual energy output. 634 The effect of these actions will result in changes in reported CO 2 emissions and/or energy output by an affected EGU. These actions include:

 heat rate improvements;

 fuel switching to a fossil fuel with lower carbon content (e.g., from coal to natural gas);

 integrated RE; 635 and

 CHP, including retrofit of an affected EGU to a CHP configuration, or revising the useful energy outputs

634 Monitoring and reporting requirements for affected EGU CO 2 emissions and useful energy output are addressed in section VIII.F. 635 “Integrated RE” refers to RE that is directly incorporated into the mechanical systems and operation of the EGU. An example is a solar thermal energy system used to preheat boiler feedwater. Such approaches reduce the amount of fossil fuel heat input per unit of useful energy output.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 900 of 1275 (electrical and thermal) at an affected EGU already operating in a CHP configuration. 636 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 2 emissions at the stack level. Stack monitoring would reflect reductions in CO 2 emissions from efficiency improvements, changes in fuel use (including incorporation of RE), and other on-site changes. Where states are implementing a rate-based plan, affected EGUs must also report useful energy output. (2) Actions with additional accounting and reporting requirements. Certain actions that may be taken at an affected

EGU to reduce CO 2 emissions, specifically application of CCS and CCU, and use of biomass, require additional accounting and reporting.

636 The emission reduction potential from CHP stems from the unit using less fuel for producing useful electrical and thermal outputs than would be required to run separate electrical and thermal units. The emission reduction would depend on the type of affected EGU and available steam hosts in the vicinity of the affected EGU. A conventional combustion turbine generator, for example, converted into a CHP unit could effectively result in a reduction of 25 percent or more in the reported CO 2 emission rate. The potential retrofitted EGU CHP market consists of converted simple cycle turbines, older steam plants in urban areas, and combined cycle units near beneficial thermal loads.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 901 of 1275 (a) Application of CCS. Affected EGUs may utilize retrofit CCS technology to reduce reported stack CO 2 emissions from the EGU. 637 Affected EGUs that apply CCS under a state plan must meet the same reporting and sequestration requirements for sequestered CO 2 as new units with CCS capability subject to the final CAA section 111(b) rule for new EGUs. 638 Specifically, the final CAA section 111(b) rule for new sources requires that, if a new affected EGU uses CCS to meet the applicable CO 2 emission limit, the EGU must report in accordance with 40 CFR part 98 subpart PP (Suppliers of Carbon Dioxide), and the captured CO 2 must be injected at a facility or facilities that report in accordance with 40 CFR part 98 subpart RR (Geologic Sequestration of Carbon

637 Addition of retrofit CCS technology should not trigger CAA section 111(b) applicability for modified or reconstructed sources. Pollution control projects do not trigger NSPS modifications and addition of CCS technology does not count toward the capital costs of reconstruction. 638 Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 902 of 1275 Dioxide). 639,640 See 40 CFR part 60.46Da(h)(5) and part 60.5555(d). Taken together, these requirements ensure that the amount of captured and sequestered CO 2 will be tracked as appropriate at project- and national-levels, and that the status of the CO 2 in its sequestration site will be monitored, including air-side monitoring and reporting. As detailed in the preamble for the CAA section 111(b) standards for new EGUs, the EPA is convinced that there is ample evidence that CCS is technically feasibleand that partial CCS can be implemented at a new fossil fuelfired steam generating EGU at a cost that is consistent with the cost of other dispatchable, non-NGCC generating options. In the June 2014 proposal, the EPA noted that CCS technology at existing EGUs would entail additional considerations beyond those at issue for newly constructed EGUs. Specifically, the

639 The final CAA section 111(b) 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 2 was captured, and (2) the e-GGRT ID(s) for, and mass of CO 2 transferred to, each GS site reporting under subpart RR. As noted, the final 111(b) rule also requires that any affected EGU unit that captures CO 2 to meet the applicable emissions limit must transfer the captured CO 2 to a facility that reports under 40 CFR part 98 subpart RR. 640 Under final requirements in the CAA 111(b) NSPS, any well receiving CO 2 captured from an affected source, be it a Class VI or Class II well, must report under subpart RR. A UIC Class II well’s regulatory status does not change because it receives such CO 2 , nor does it change by virtue of reporting under subpart RR.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 903 of 1275 cost of integrating a retrofit CCS system into an existing facility would be expected to be substantial, and some existing EGUs might have space limitations and thus might not be able to accommodate the expansion needed to install CCS. Further, the EPA noted that aggregated costs of applying CCS as a component of the BSER for the large number of existing fossil fuel-fired steam EGUs would be substantial and would be expected to affect the cost and potentially the supply of electricity on a national basis. For those reasons the EPA did not propose nor finalize CCS as a component of the BSER for existing EGUs. However, the EPA noted that CCS may be a viable CO 2 mitigation technology at some existing sources and that it would be available to states and to sources as a compliance option. Numerous commenters agreed with the EPA’s proposed determination that CCS technology is not part of the BSER building blocks for existing EGUs. Other commenters opposed inclusion of CCS requirements in state plans and provided specific reasons why CCS would not be applicable in certain states. Many commenters felt that CCS technology is not adequately demonstrated and is not economically practical at this time. Other commenters argued that CCS is an available technology and that it can be implemented at more EGUs than predicted by EPA modelling. Some commenters noted that there are opportunities to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 904 of 1275 reduce the cost of CCS implementation by selling the captured CO 2 for use in Enhanced Oil Recovery (EOR) operations. One commenter expressed concern that federal requirements under the Greenhouse Gas Reporting Program – specifically the requirement (mentioned above) to report under 40 CFR part 98 subpart RR – would foreclose, rather than encourage, the use of captured CO 2 for EOR. The EPA received similar public comments on the CAA 111(b) proposal for new EGUs and has addressed those in the preamblefor the final standards of performance and in the Response-toComments (RTC) document for that rulemaking. (b) Application of CCU. The EPA received comments suggesting that carbon capture and utilization (CCU) technologies should

also be allowed as a CO 2 emission rate adjustment measure for

affected EGUs. Potential alternatives to storing CO 2 in geologic formations are emerging and these relatively new potential alternatives may offer the opportunity to offset the cost of CO 2 capture. For example, captured anthropogenic CO 2 may be stored in solid carbonate materials such as precipitated calcium carbonate (PCC) or magnesium or calcium carbonate, bauxite residue carbonation, and certain types of cement through mineralization. The carbonate materials produced can be tailored to optimize performance in specific industrial and commercial applications.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 905 of 1275 For example, these carbonate materials have been used in the construction industry and, more recently and innovatively, in cement production processes to replace Portland cement. The Skyonics Skymine® project, which opened its demonstration project in October 2014, is an example of captured

CO 2 being used in the production of carbonate products. This plant converts CO 2 into commercial products. It captures over 75,000 tons of CO 2 annually from a San Antonio, Texas, cement plant and converts the CO 2 into other products including sodium

carbonate and sodium bicarbonate. 641 Other companies – including

Calera 642 and New Sky 643 – also offer commercially available technology for the beneficial use of captured CO 2 . These processes can be utilized in a variety of industrial applications – including at fossil fuel-fired power plants. However, consideration of how these emerging alternatives

could be used to meet CO 2 emission performance rates or state CO 2 emission goals would require a better understanding of the ultimate fate of the captured CO 2 and the degree to which the method permanently isolates the captured CO 2 or displaces other

CO 2 emissions from the atmosphere. Several commenters also suggested that algae-based CCU

641 http://skyonic.com/technologies/skymine. 642 http://www.calera.com/beneficial-reuse-of-co2/process.html. 643 http://www.newskyenergy.com/index.php/products/carboncycle.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 906 of 1275 (i.e., the use of algae to convert captured CO 2 to useful products – especially biofuels) should be recognized for its potential to reduce emissions from existing fossil-fueled EGUs. Unlike geologic sequestration, there are currently no uniform monitoring and reporting mechanisms to demonstrate that these alternative end uses of captured CO 2 result in overall

reductions of CO 2 emissions to the atmosphere. As these alternative technologies are developed, the EPA is committed to work collaboratively with stakeholders to evaluate the efficacy of alternative utilization technologies, to address any regulatory hurdles, and to develop appropriate monitoring and reporting protocols to demonstrate CO 2 reductions. In the meantime, state plans may allow affected EGUs to use qualifying CCU technologies to reduce CO 2 emissions that are subject to an emission standard, or those that are counted when demonstrating achievement of the CO 2 emission performance rates

or a state rate-based or mass-based CO 2 emission. State plans must include analysis supporting how the proposed qualifying CCU technology results in CO 2 emission mitigation and provide monitoring, reporting, and verification requirements to

demonstrate the reductions. The EPA would then review the appropriateness and basis for the analysis and the verification requirements in the course of its review of the state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 907 of 1275 (c) Biomass co-firing and repowering. Affected EGUs may use qualifying biomass in order to reduce CO 2 emissions that are subject to an emission standard requirement, or those that are counted when demonstrating achievement of the CO 2 emission performance rates or a state rate-based or mass-based CO 2 emission goal. Not all forms of biomass are expected to be approvable (see section below for considerations pertaining to biomass use in state plans). A state would propose qualifying biomass feedstocks or categories of biomass feedstocks in its plan and the proposed treatment of biogenic CO 2 emissions, including measures to ensure emission reduction benefits. State plans must include analysis supporting how proposed qualifying feedstocks or feedstock categories are considered appropriate as

a CO 2 emission mitigation approach as well as the proposed treatment of biogenic CO 2 emissions (i.e., the proposed level of biogenic CO 2 emissions from use of the biomass feedstock that would not be counted when demonstrating compliance with an emission standard, or when demonstrating achievement of the CO 2 emission performance rates or a state rate-based or mass-based

CO 2 emission goal) and quality control measures. The EPA would review the appropriateness and basis for such determinations and accounting measures in the course of its review of a state plan. The EPA received multiple comments supporting the use of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 908 of 1275 biomass feedstocks as a means of reducing CO 2 emissions within state plans. Several commenters also asserted that states should be able to determine how biomass can be used in their plans. Additionally, the EPA received a range of comments regarding the

valuation of CO 2 emissions from biomass combustion. Some argued

that all biomass feedstocks should be considered “carbon neutral,” while others maintained that only the full stack

emissions from biomass combustion should be counted. As discussed in the next section, the revised Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources 644 and the 2012 Science Advisory Board peer review of the 2011 Draft

Framework find that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral.” 645 Other comments focused on the use of sustainably-derived agricultural and forest biomass feedstocks, including stakeholders who supported and those against such feedstocks as approvable elements, and those who wanted further definition of these feedstocks. As discussed above, states can propose qualifying biomass feedstocks or feedstock categories in state plans. The EPA will review the appropriateness and basis for determining

644 www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-CO2-Emissions.pdf. 645 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 909 of 1275 qualifying biomass feedstocks or feedstock categories in its review of a state plan. (i) Considerations for use of biomass in state plans. As detailed in the President’s Climate Action Plan, 646 part of the strategy to address climate change includes efforts to protect and restore our forests, as well as other critical landscapes including grasslands and wetlands, in the face of a changing climate. This country’s forests currently play a critical role in addressing carbon pollution, removing nearly 12 percent of total U.S. greenhouse gas emissions each year. Conservation and sustainable management can help ensure our forests and other lands will continue to remove carbon from the atmosphere while also improving soil and water quality, reducing wildfire risk and enhancing forests’ resilience in the face of climate change. The EPA recognizes that some biomass-derived fuels can play

a role in CO 2 emissions reduction strategies. The EPA also anticipates that some states may consider biomass-derived fuels used in electricity generation as a way to mitigate CO 2 emissions, and will include them as part of their state plans to meet the emission guidelines. With regard to assessing qualifying biomass specified in

646 www.whitehouse.gov/sites/default/files/image/ president27sclimateactionplan.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 910 of 1275 state plans, the EPA generally acknowledges the CO 2 emissions reduction and climate policy benefits of waste-derived biogenic

feedstocks 647 and certain forest- and agriculture-derived industrial byproduct feedstocks, based on the conclusions supported by a variety of technical studies, including the

revised Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources. Such waste-derived and certain industrial byproduct biomass feedstocks would likely be approvable as qualifying biomass in a state plan. In addition, given the importance of sustainable land management in achieving the carbon reduction goals of the President’s Climate Action Plan, sustainably-derived agricultural and forest biomass feedstocks may also be acceptable as qualifying biomass in a state plan, if the state-supplied analysis of proposed qualifying feedstocks or feedstock categories can adequately demonstrate that such feedstocks or feedstock categories are considered appropriate as

a CO 2 emission mitigation approach. Many states have recognized the importance of forests and

647 Types of w aste-derived biogenic feedstocks may include: landfill gas generated through the decomposition of MSW in a landfill; biogas generated from the decomposition of livestock waste, biogenic MSW, and/or other food waste in an anaerobic digester; biogas generated through the treatment of waste water, due to the anaerobic decomposition of biological materials;livestock waste; and the biogenic fraction of MSW at waste-toenergy facilities (as discussed in section VIII.G.1.b(3)(c) below).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 911 of 1275 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 ForestPractice Regulations support sustained production of highquality 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 912 of 1275 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 theemission guidelines, they may consider how the role of wastederived feedstocks as well as sustainably-derived biomass and sustainable forestry and agriculture programs, such as the examples highlighted above, may help them meet their emission reduction goals. In addition, the EPA’s work on assessing*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 913 of 1275 biogenic CO 2 emissions from stationary sources may also help inform states’ efforts to assess the role of different biogenic feedstocks in their plans and broader climate strategies. In November 2014, the agency released a second draft of the technical report, Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources . The revised Framework, and the EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft

Framework , finds that it is not scientifically valid to assume that all biogenic feedstocks are “carbon neutral” and that the net biogenic CO 2 atmospheric contribution of different biogenic feedstocks generally depends on various factors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production. 648 The EPA is engaging in a second round of targeted peer review with the SAB in 2015. 649 Information in the

revised Framework and the second SAB peer review process, including stakeholder comments, should assist both states and the EPA in assessing qualifying biomass feedstocks included in state plans. (ii) Biomass co-firing. Affected EGUs may use qualifying biomass

648 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. 649 www.epa.gov/sab.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 914 of 1275

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 qualifying biomass feedstocks and treatment of biogenic CO 2 emissions in state plans, along with supporting analysis and quality control measures. The EPA will review the appropriateness and basis for such determinations and accounting measures in the course of its review of a state plan. An affected EGU using qualifying biomass as a fuel must monitor and report both its overall CO 2 emissions and its biogenic CO 2 emissions. If biomass is to be used as an emission reduction measure in a state plan, the plan must specify requirements for reporting biogenic CO 2 emissions from affected EGUs. Reporting requirements for biogenic CO 2 emissions under 40 CFR 98(§§ 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) are an acceptable default reporting approach that would be approvable when combined with other state plan components. However, the EPA may approve other approaches included in a state plan. (iii) Biomass repowering. Affected EGUs could fully repower to use primarily qualifying biomass. The characteristics of affected sources, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 915 of 1275

biomass fuels instead of fossil fuels becomes a non-affected

EGU. 650 An EGU repowering with less than 90 percent biomass would remain an affected EGU and provide a reduction option similar to that described earlier in this section, with the same processes for proposing qualified biomass feedstocks or feedstock categories and biogenic CO 2 emissions evaluation, monitoring and reporting requirements. Entities switching to significantly higher amounts of biomass use may be subject to other permitting requirements outside of this rule. b. Actions taken to adjust the CO 2 emission rate of an affected

EGU. This section describes how measures 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 2 emission rate of an affected EGU. This section discusses the required accounting method for adjusting a CO 2 emission rate, as well as general eligibility requirements that apply to different categories of measures that may be used to adjust a CO 2 emission rate. Where relevant, this section also discusses additional specific accounting methods and other relevant requirements that apply to different categories of measures.

650 For such an EGU to be considered non-affected, the EGU should be subject to a federally enforceable or practically enforceable condition, expressed in (for example) a construction permit or otherwise, that limits the amount of fossil fuel that may be used to 10 percent or less.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 916 of 1275

A CO 2 emission rate adjustment may be applied in different rate-based state plan contexts. For example, in a rate-based emission trading program, adjustments may be applied through the

use of ERCs. 651 Alternatively, under a state measures plan that does not employ rate-based trading, adjustments may be applied by the state to the reported CO 2 emission rate of the affected fleet of EGUs. Regardless of the type of plan in which an adjustment is applied, the same basic accounting and general eligibility requirements described in this section will apply. As discussed in this section, a wide range of actions may be taken to adjust the reported CO 2 emission rate of an affected EGU in order to meet a rate-based emission standard and/or

demonstrate achievement of a state CO 2 rate-based emissions goal.

All of the measures described in this section will substitute for generation from affected EGUs or avoid the need for generation from affected EGUs, thereby reducing CO 2 emissions.

This includes RE measures included in the EPA’s determination of the BSER, as well as other measures that were not included in the determination of the BSER, such as other RE resources,

651 ERCs may be issued for the measures presented in this section, as well as to affected EGUs that emit at a CO 2 emission rate below their assigned emission rate limit. ERC issuance and trading is discussed in detail in section VIII.G. That section addresses the accounting method for ERC issuance to affected EGUs that perform below their assigned CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 917 of 1275 demand-side EE, CHP, WHP, electricity transmission and distribution improvements, nuclear energy, and international energy imports. 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 2 emissions from affected EGUs under a rate-based state plan. However, the actions that a state could include in a rate-based state plan are not necessarily limited to those described in this section. Other specific actions not listed here may be incorporated in a state plan, provided they meet the general eligibility requirements listed in this section, as well as the other relevant requirements in the emission guidelines. 652 Nor are states required to include in their plans all of the actions that are described in this

section. This section discusses the basic accounting method for adjusting the reported CO 2 emission rate of an affected EGU, through the use of measures that substitute for or avoid generation from affected EGUs. That method is based on adding

MWh from such measures to the denominator of an affected EGU’s reported CO 2 emission rate. Those additional MWh are based on quantified and verified electricity generation or electricity

652 These requirements are discussed in section VIII.D.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 918 of 1275 savings from eligible measures. This section also addresses general eligibility requirements for resources that are used to adjust an affected

EGU’s CO 2 emission rate. Specific eligibility and accounting methods that apply in order to determine MWh generation or savings from different types of resources are also addressed, where relevant, including for:

 hydropower;

 biomass;

 waste-to-energy;

 demand-side EE and other efficiency measures;

 transmission and distribution (T&D) measures that increase T&D efficiency or reduce electricity end-use;

 CHP at non-affected sources;

 waste heat to power (WHP); and

 nuclear power. (1) General accounting approach for adjusting a CO 2 emission rate. In this final rule, the reported CO 2 emission rate of an affected EGU may be adjusted based on quantified and verified MWh from qualifying zero-emitting and low-emitting resources, as described in sections VIII.G.1.b.(2)-(9) below. These MWh are added to the denominator of an affected EGU’s reported CO 2 emission rate, resulting in a lower adjusted CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 919 of 1275

The measures described in these sections reduce mass CO 2emissions from affected EGUs by substituting zero- or lowemitting generation for generation from affected EGUs, or by avoiding the need for generation altogether (in the case ofresources that lower electricity demand through improved demandside EE and demand-side management). In both of these cases, generation from an affected EGU is replaced, through substitute generation or a reduction in electricity demand. To the extent that qualifying zero-emitting and low-emitting resources result in reduced generation and CO 2 emissions from an individual affected EGU, those emission impacts are reflected in lower reported CO 2 emissions and a reduction in MWh generation from the affected EGU. However, while there will be a reduction in CO 2 emissions, the fact that both CO 2 emissions and MWh generation are reduced means that such impacts do not alter the reported CO 2 emission rate of the affected EGU. As a result, the MWh of replacement generation must be added to the denominator of the reported CO 2 emission rate, in order to represent those impacts in the form of an adjusted CO 2 emission rate. In this manner, adding MWh from these resources to the denominator of an

affected EGU CO 2 emission rate allows mass CO 2 emission reductions from these measures to be fully reflected in an adjusted CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 920 of 1275 The following provides a simple calculation example of how MWh of replacement generation added to the denominator of an affected EGU’s reported CO 2 emission rate results in a lower adjusted CO 2 emission rate. Assume an affected EGU with CO 2 emissions of 200,000 lb and electric generation of 100 MWh during a reporting period. The affected EGU’s reported CO 2 emission rate is 2,000 lb/MWh (200,000 lb CO 2 /100 MWh = 2,000 lb/MWh). When complying with its rate-based emission limit, the affected EGU submits 10 ERCs, representing 10 MWh of replacement generation. 653 Adding 10 MWh of replacement generation to the reported MWh generation of the affected EGU results in an adjusted CO 2 emission rate of 1,818 lb CO 2 /MWh (200,000 lb

CO 2 /110 MWh = 1,818 lb CO 2 /MWh).

In the case of rate-based CO 2 emission standards, an affected EGU demonstrates compliance with the emission standards if the affected EGU’s adjusted CO 2 emission rate calculated in the aforementioned manner is less than or equal to the applicable CO 2 emission standard rate. 654 In the case of a state measures plan, quantified and verified MWh from eligible state

653 Requirements for the issuance of ERC and a further discussion of how ERCs are used in compliance with rate-based emission limits are addressed in section VIII.G.3. 654 Any ERCs used to adjust a CO 2 emission rate must meet requirements in the emission guidelines, which are described in section VIII.D.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 921 of 1275 measures are used by the state to administratively adjust the reported CO 2 emission rate of affected EGUs in the aforementioned

manner. The CO 2 emission performance rates or rate-based CO 2 goal in the emission guidelines are met if the adjusted CO 2 emission rate of affected EGUs in a state is at or below the specified CO 2 emission rate in a state plan that applies for an identified plan performance period. Numerous commenters requested that the EPA ensure consistency between goal-setting calculations and the methodology used to demonstrate achievement of a CO 2 emission rate under a state plan. This approach for adjusting a CO 2 emission rate corresponds with how RE, the one component of the BSER that involves adjustment of a CO 2 emission rate, is represented in the CO 2 emission performance rates in the emission guidelines. Specifically, in the calculation of final CO 2 emission performance rates, the MWh of RE are reflected in two adjustments of the rate: a reduction of CO 2 emissions from affected EGUs in the numerator and a one-to-one replacement of affected EGU generation in the denominator, where it is assumed that replaced generation from an affected EGU is subtracted from the denominator and the same number of zero-emitting MWh are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 922 of 1275

added. 655 When demonstrating achievement of a CO 2 emission performance rate, the reported CO 2 emissions already reflect the actualemission reductions from the deployment of qualifying nonemitting and low-emitting resources across the regional grid; a further adjustment of CO 2 emissions would double count CO 2 emissions impacts across the grid. Consistent with the EPA’s

calculation of the CO 2 emission performance rates and state ratebased CO 2 goals in the emission guidelines, the zero-emitting MWhs (from substitute generation or a reduction in electricity demand) must still be added to the denominator of a reported CO 2 emission rate to calculate an adjusted CO 2 emission rate that appropriately reflects the replaced generation. Several commenters suggested that the EPA consider theregional nature of the electricity grid and how RE and demandside EE impacts generation and CO 2 emissions across the grid when accounting for the impacts of RE and demand-side EE measures in a rate-based plan approach. This MWh accounting structure corresponds with the regional treatment of RE resources in the BSER that provide substitute generation in the EPA-calculated CO 2 emission performance rates in the emission guidelines.

655 For a detailed discussion of this method, see Section VI.C.3. Form of the Performance Rates, in the Equation subsection.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 923 of 1275 Consistent with assumptions used in calculating the CO 2 emission performance rates in the emission guidelines, affected EGUs and states can take full credit for the MWh resulting from eligible measures they are responsible for deploying, no matter where those measures are implemented. CO 2 emission reductions from the eligible measures may occur across the region, however, an affected EGU or a state may only take credit for avoided CO 2 emissions at that affected EGU or set of EGUs in question, as reflected in the reported stack CO 2 emissions of affected EGUs. Because of the separate accounting of MWhs and CO 2 emissions, with emission impacts inherent in reported stack CO 2 emissions and zero-emitting MWh impacts requiring explicit adjustments, the accounting method corresponds with the use of MWh-denominated ERCs in the rate-based emission trading framework specified in this rule. The accounting method only requires a quantification of the MWh generated or avoided by an eligible measure, and thus credits or adjustments can be denominated in MWh and do not need to represent an approximation

of the CO 2 emission reductions that result from those MWhs. This creates a crediting system or rate adjustment process that is simpler to implement than one that requires an approximation of

avoided CO 2 emissions. The MWh accounting method also creates a crediting system*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 924 of 1275 or rate adjustment process that is indifferent to the rate-based

CO 2 emission goals of individual states, or the specific CO 2 emission rate standards that states may apply, and the relativestringency of those goals or standards. Use of ERCs in ratebased emission trading programs is addressed in detail in

section VIII.G.3. This MWh accounting method also addresses interstate effects, because it inherently accounts for how generation replacement and CO 2 emission reduction impacts may cross state borders. For example, if the accounting method was informed by

avoided CO 2 emission rates, it could create perverse incentives for development of zero- or low-emitting resources in states that result in the greatest calculated estimate of CO 2 emission reductions for each replacement MWh. Instead, this accounting

method is indifferent to avoided CO 2 emission rates and creates the same number of zero-emitting credits or adjustment for each MWh of energy generation or savings, wherever they occur. For a detailed discussion on how the accounting method addresses interstate effects, see section VIII.G.2. (2) General eligibility requirements for resources used to adjust a CO 2 emission rate. The EPA is finalizing certain general eligibility requirements for resources used to adjust a CO 2 emission rate. These requirements align eligibility with certain*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 925 of 1275 factors and assumptions used in establishing the BSER, and by extension, application of the BSER to the performance levels established for affected EGUs in the emission guidelines, as

well as state rate and mass CO 2 goals. These requirements are appropriate, as they align measures that may be used in a state plan with the EPA’s assessment of the BSER. 656 These general requirements also address potential interactions among rate and mass plans, as discussed more fully in section VIII.G.2. As discussed in the subsections that follow, the general eligibility criteria address:

 the date from which MWh from eligible measures may be counted, and applied toward adjusting a CO 2 rate;

 the date from which eligible measures may be installed (e.g., installation of RE generating capacity and installation of EE measures); and

 the need to demonstrate that eligible measures replace or avoid generation from affected EGUs. (a) Eligibility date for MWh generation and savings. Electricity generation and electricity savings that occur during a plan performance period may be applied to adjust a CO 2 emission rate.

656 For example, eligibility requirements include installation dates for eligible RE measures that may be used in a state plan. These dates generally align with the dates used for broadly defining incremental RE resources that were considered in establishing the BSER.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 926 of 1275 Specifically, this means that any quantified and verified MWh of electricity generation or electricity savings that occur in 2022 and future years, from an eligible measure, may be applied toward adjusting a CO 2 emission rate. The eligible measures themselves may be installed in any year after 2012, as described

below. 657 For example, MWh generation in 2022 from a wind turbine installed in 2013 may be applied toward adjusting a CO 2 emission

rate. Further, 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 2 emission rate in 2023 or future years, without limitation. 658 These MWh may be banked from the interim to final compliance periods.

The EPA notes that states can submit a rate-based state plan that encourages early action by allowing MWhs generated from 2013-2021 to be used to adjust the CO 2 rate of affected EGUs during the plan performance period (2022 and subsequent years). In order for this type of provision to be approvable in a state

657 For demand-side EE, this eligibility date may require special considerations for EM&V plans. EM&V requirements are addressed in subsection VIII.C.3. 658 Similarly, as discussed in section VIII.C.2.b.(2).(a), allowances may be banked in a mass-based trading program.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 927 of 1275 plan, it must meet certain conditions. These MWhs must be from eligible measures implemented after 2012. The state must provide provisions for adjustment of CO 2 emission performance rates or

rate-based state CO 2 goals (applied during the plan performance periods in 2022 and future years) downward based upon the number of MWhs that are issued from 2013-2021, such that the level of emission reductions is equivalent to or more stringent than that which would have been achieved had eligible MWh been limited to those generated during the plan performance periods in 2022 and future years. This downward adjustment of CO 2 emission performance rates or rate-based state CO 2 goals must be calculated based upon a projection of total CO 2 emissions, total MWh generation from affected EGUs, and total ERCs that would have been used to demonstrate compliance if the state had

elected to meet the CO 2 emission performance rates or rate-based

state CO 2 goals using only eligible MWh issued in 2022 and subsequent years. (b) Eligibility date for installation of RE/EE and other measures. RE generating capacity and demand-side EE measures that are installed after 2012 are eligible for use in adjusting

a CO 2 emission rate. This aligns with treatment of RE in the BSER. Other eligible measures, such as CHP, nuclear power and DSM, also must be installed after 2012. This 2012 date applies*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 928 of 1275 consistent eligibility requirements to all forms of zero- and low-emitting eligible generating capacity that may be used to adjust a CO 2 emission rate. As described above, only the MWh of energy savings that occur in 2022 and subsequent years as a result of these measures may be applied toward adjusting a CO 2 emission rate. This eligibility date criterion is consistent with the date of installation for “incremental” RE capacity that is included in BSER building block 3, which is the basis for RE MWh incorporated in the CO 2 emission performance rates for affected EGUs in the emission guidelines. For more information on RE in the BSER, see section V.E. Many commenters asserted that proposed state goals did not sufficiently account for actions

states take that reduce CO 2 emissions prior to the first plan performance period, and therefore requested that MWhs of electricity generation or electricity savings that occur prior to the first plan performance period be eligible to apply toward adjusting the CO 2 emission rates of affected EGUs. The EPA recognizes the importance of early state action as the basis for significant CO 2 emission reductions and as a key part of enabling state plans to achieve the CO 2 emission performance levels or state CO 2 goals. The ability to count eligible measures installed in 2013 and subsequent years for the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 929 of 1275 MWhs they generate during a plan performance period provides significant recognition for early action, corresponding with the BSER framework that is based on cost-effective actions that many sources are already doing, while still conforming to CO 2 performance rates and state goals that are forward-looking. 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 2 emission performance levels and rate-based state CO 2 goals in the emission guidelines. The specifics of these changes are addressed in section V.A.3. Three examples of those changes are provided

below. First, affected EGUs that have maximized their CO 2 emission reduction opportunities available through early action will be better positioned to meet the BSER technology-source specific CO 2 emission rate that is uniformly applied to all affected EGUs in a technology category. For example, a steam generating unit that has already reduced its CO 2 emission rate through a heat rate improvement may have a CO 2 emission rate of 2,000 lb/MWh whereas its rate was 2,100 lb/MWh prior to the improvement. Therefore, it has less distance to cover to meet the technology-specific CO 2 emission performance rate for steam generating units finalized

in this action.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 930 of 1275 Second, generation from existing RE capacity installed prior to 2013 has been excluded from the EPA’s calculation of

the CO 2 emission performances rates in the emission guidelines. That RE generating capacity will still provide zero-emitting generation to the grid and will better position states and

affected EGUs to meet the CO 2 performances rates or state rateor mass-based CO 2 goals. 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 2017. Because demand-side EE is not used in calculating the CO 2 emission performance rates in the emission guidelines, this is no longer the case. Furthermore, eligible demand-side EE actions that occur after 2012 can be applied toward adjusting the CO 2 emission

rates of affected EGUs. (c) Demonstration that measures substitute for grid generation. Eligible measures must be grid-connected. This eligibility criterion 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 equipment that is connected to the electricity grid. EE measures only avoid electric*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 931 of 1275 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 2 emissions. However, eligible measures must be able to substitute for generation from affected EGUs as defined under this rule, and thus must be tied to the electrical grid. (d) Geographic eligibility. RE generation and demand-side EE measures may occur in any state or territory, with certain limitations, as described below. To the extent these measures are tied to a state plan, 659 these measures may be used to adjust

a CO 2 emission rate, regardless of whether the RE generation or demand-side EE savings occur inside or outside the state or territory. 660 This approach is generally consistent with the

659 As used here, a measure is “tied to a state plan” if it is issued an ERC under a rate-based emission standard, or under a state measures plan represents quantified and verified MWh energy generation or energy savings achieved by an approved state measure. 660 For example, under a rate-based emission standard with credit trading, ERCs may be issued for qualifying actions that occur both inside and outside the state, provided the measures meet*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 932 of 1275 approach used in building block 3 of the BSER, which reflects regionally available RE and interstate effects. This approach recognizes that RE and demand-side EE measures have impacts on electricity generation across the electricity system, both within and beyond a state’s borders. A more in-depth discussion

of the basis for treatment of in-state and out-of-state RE and EE is provided below. For consistency, this geographic eligibility criterion applies to all other eligible measures that are used to adjust a

CO 2 emission rate under a state plan. These measures will have similar interstate impacts as RE and demand-side EE on electricity generation across the interconnected electricity system. State plans must demonstrate that emission standards and state measures (if applicable) are non-duplicative. Given the geographic eligibility approach described here, this includes demonstration that a state plan does not provide for recognition of a MWh, for use in adjusting the CO 2 emission rate of an

requirements of EPA-approved state regulations and the provider applies to the state for the issuance of ERCs. Similarly, under a state measures plan, a state might include state requirements such as an RPS, where compliance with the RPS can be met through out-of-state RE generation. In this plan context, MWh of RE generation used to comply with the state RPS could be used by the state to adjust the CO 2 emission rate of the fleet of affected EGUs in the state when demonstrating that its plan has achieved the state’s rate-based CO 2 goal.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 933 of 1275 affected EGU, if the MWh is being used for such a purpose under another state plan. Discussion of how such a demonstration can be made in the context of a rate-based emission trading program

is in section VIII.D. 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. 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 2 goals, but that RE was functionally credited to other states for use in meeting their goals because it was associated with measures (such as an RPS) likely to be included in another state’s plan. This concern has been addressed through changes in the BSER RE assumptions in the final rule. This includes regionalization of the RE building block, and removal of existing RE capacity constructed prior to 2012 from the building block. The result of these changes is that the RE incorporated*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 934 of 1275 in the BSER is more equally shared across states. (i) Measures that occur in states with mass-based plans. As discussed above, eligible measures for adjusting the CO 2 emission rate of an affected EGU may occur in any state, with certain conditions. This includes eligible measures that occur in astate with an EPA-approved plan that is meeting a state massbased CO 2 goal. However, measures that occur in such mass-based states must meet additional eligibility criteria to be used to adjust the CO 2 emission rate of an affected EGU in a state with a rate-based plan.

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 2 emissions from affected EGUs. Where states with mass-based plans implement

mass-based CO 2 emission standards, CO 2 emissions reductions from affected EGUs must occur in order to comply with these emissionstandards and, unlike the rate-based approach, zero- and lowemitting MWhs do not play a specified role in demonstrating that

the mass-based standards have been met. 661 Since they are not counted in the mass-based demonstration, eligible measures

661 Where such measures substitute for generation from affected EGUs subject to a mass CO 2 emission limit, such measures reduce the cost of meeting those mass emission limits, but do not result in incremental CO 2 emission reductions.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 935 of 1275

located in mass-based states could be used in a state with a rate-based plan to adjust the CO 2 emission rate of affected EGUs. Such adjustments would obviate the need for comparable CO 2 emission reductions at affected EGUs in the rate-based state or the use of other measures to make a rate adjustment. In this scenario, to the extent that eligible measures substitute solely for generation from affected EGUs in a state with mass-based emission limits, and are also used to adjust the reported CO 2 emission rate of affected EGUs in a rate-based state, no

incremental CO 2 emissions reductions would occur in the ratebased state as a result of the eligible measures. 662 The result

would be a loss in net CO 2 emission reductions that would otherwise occur across the two states. These dynamics are

further addressed in section VIII.G.2. For measures providing zero- or low-emitting generation located in a mass-based state, it must be demonstrated that the energy generated is delivered to meet electricity load in a state with a rate-based plan. 663 Some examples of documentation that can serve as a demonstration include a power delivery

662 As used here, incremental emission reductions refers to emission reductions that are above and beyond what would be achieved solely through compliance with the emission standards in the mass-based state. 663 This does not need to necessarily be the state where the MWh of energy generation from the measure is used to adjust the CO 2 emission rate of an affected EGU.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 936 of 1275 contract or power purchase agreement. The EPA is giving states flexibility regarding the nature of this demonstration, but a state plan must describe the nature of the required demonstration and have it be approved by the EPA. Under an emission standards plan, this demonstration must be made by the provider of the measure seeking ERC issuance under the rate-based emission standards in a rate-based state, as part of the eligibility application for the measure. 664 Under a state measures plan, this demonstration must be made by the rate-based state as part of its demonstration of how its state

measures meet the CO 2 emission performance rates or achieve the

state rate-based CO 2 emission goal for affected EGUs. 665 In the case of either an emission standards plan or state measures plan, the rate-based state must include in its state plan provisions that describe what it will consider a sufficientdemonstration of geographic eligibility for zero- or lowemitting generation under rate-based emission standards, or geographic eligibility of state measures that can be used to adjust the reported CO 2 emission rate of affected EGUs.

664 Requirements for ERC issuance are addressed in subsection VIII.C.2. 665 This demonstration is part of a state’s annual report to the EPA, outlining the eligibility of MWh used to adjust the reported CO 2 emission rates of affected EGUs under a rate-based state measures plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 937 of 1275 Further examples of eligible demonstrations and how they should be outlined in state plans is provided in section

VIII.G.2. (ii) Measures that occur in states and territories that are not interconnected to the grid or do not have affected EGUs. States and territories that are not interconnected to the grid in the continental U.S. or that do not have any affected EGUs within their borders may be providers of credits to adjust CO 2 emission rates. In its supplemental proposal for this proposed rulemaking, the EPA sought comment on whether or not jurisdictions without affected fossil fuel generation units subject to the proposed emission guidelines should be authorized to participate in state plans. Commenters were supportive of allowing those jurisdictions without affected EGUs the opportunity to participate in state plans. CO 2 reduction measures in areas without affected EGUs have the potential to provide cost-effective opportunities to reduce emissions and should be available on a voluntary basis to affected EGUs. Commenters noted that some tribes, for example, have many untapped RE resources that could be developed, and they should be able to realize the benefits of contributing to a state plan. Commenters stated that because of the integrated nature of the U.S. electricity grid, it is appropriate to allow all jurisdictions*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 938 of 1275 with the ability to contribute to and benefit from CO 2 emission

reductions or CO 2 emission rate adjustments. For rate-based states and territories, they must adhere to EM&V standards, installation dates, and any other criteria that apply to all states. Section VIII.G.3 below identifies and discusses the EM&V criteria used to quantify MWh savings from demand-side EE and generation from zero-emitting sources. States, including areas of Indian country, that do not have any affected EGUs may provide ERCs to adjust CO 2 emissions provided they are connected to the continental U.S. grid and have a powerpurchase agreement or contract for delivery of the zero- or lowemission power, along with meeting the other requirements for eligibility. Mass-based states and territories are not allowed to provide ERCs for zero- or lower-emission power generation if they are not connected to the continental U.S. grid and, hence, not able to also deliver the power. For demand-side EE adjustments where there is no power delivery, the emission

reductions must meet the demonstration criteria that also applies to demand-side EE reductions in all other mass-based

states. (iii) Measures that occur outside the U.S. The EPA will work with states using the rate-based approach and interested in allowing the use of RE and demand-side EE from outside the U.S.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 939 of 1275 to adjust CO 2 emission rates. In these cases, certain conditions must be demonstrated including: the country generating the ERCs must be connected to the U.S. grid; resources must be incremental and installed after 2012 for RE and demand-side EE; all EM&V standards that apply to domestic measures must be met; and, specifically for RE, there must be a power purchase agreement or other contract for delivery of the power with an entity in the U.S. For demand-side EE adjustments where there is no power delivery, the emission reductions must meet the demonstration criteria that also applies to demand-side EE reductions in mass-based states. RE generation capacity outside the U.S. that existed prior to 2012 but was not exported to the U.S. is not considered new or incremental generation and, therefore, not eligible for adjusting CO 2 emission rates under this rule. For example, a new transmission interconnection to existing RE in Canada would not be considered incremental. See below for more specifics regarding the use of incremental hydroelectric power in a rate-based approach. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 940 of 1275 development to increase generating capacity, which could be called upon as a base load resource to supplement intermittent forms of RE generation. Commenters said that the EPA should permit the use of all incremental hydropower—both domestic and

international—towards EGU CO 2 emission rate adjustments providing that double-counting can be prevented; and the EPA acknowledges this may be allowable, as long as the specified criteria have

been met. (3) RE and demand-side EE. RE 666 and demand-side EE measures may be used to adjust a CO 2 emission rate, provided they meet the general eligibility requirements outlined above and the MWh electricity generation or electricity savings are properly quantified and verified. 667 Many commenters supported using RE deployment as measures to adjust the CO 2 emission rate of affected EGUs. Some commenters specifically agreed with the EPA’s determination that only new and incremental RE (including hydropower) should be used to adjust CO 2 emission rates. Those commenters objected to counting

666 As used in this section, RE includes electric generating technologies using RE resources, such as wind, solar, geothermal, hydropower, biomass and wave and tidal power. 667 All state plans must demonstrate that measures included in the plan are quantifiable and verifiable. See section VIII.C.2 for discussion of requirements for the issuance of ERCs, and section VIII.C.3 for discussion of EM&V requirements for use of RE and demand-side EE in a state plan.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 941 of 1275 existing RE that are already embedded in the baseline emissions and generation mix. A significant number of commenters supported the integration of RE into a rate-based credit trading system. Certain additional requirements apply for hydropower and biomass (including waste-to-energy), as described below. (a) Hydroelectric power. Consistent with other types of RE, new hydroelectric power generating capacity installed after 2012 is eligible for use in adjusting a CO 2 emission rate. In addition, a capacity uprate at an existing hydroelectric power resource (i.e., an uprate to generating capacity originally installed as of 2012 or earlier) is also eligible to adjust a CO 2 emission rate. The capacity uprate must occur after 2012. Such uprates to capacity represent incremental capacity added after 2012, which we refer to as “incremental hydroelectric power.” Generation (in MWh) from incremental hydroelectric power generating capacity is determined 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 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 942 of 1275 emission rate, regardless of the overall level of generation for the period. 668 Relicensed facilities are considered existing capacity and, therefore, are not eligible for use in adjusting a CO 2 emission rate, unless there is a capacity uprate as part of the relicensed permit. In such a case, only the incremental capacity is eligible for use in adjusting a CO 2 emission rate. 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 fromexisting fossil generation, but that new or uprated zeroemitting 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. One commenter recognized the difficulty of quantifying emission reductions due to uprated zero-emitting sources. The EPA believes the approach described is appropriate. (b) Biomass. RE generating capacity installed after 2012 that

668 For example, the overall generation from the uprated hydroelectric power plant may be higher or lower than generation levels that occurred at the plant prior to the capacity uprate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 943 of 1275 uses qualifying biomass as a fuel source is eligible for use in adjusting a CO 2 emission rate. 669 As discussed in section VIII.G.1.a.(2)(c), a state should propose qualifying biomass feedstocks and treatment of biogenic CO 2 emissions in its plan, along with supporting analysis and quality control measures, and the EPA would review the appropriateness and basis for such determinations in the course of its review of a state plan. Where an RE generating unit uses qualifying biomass, as designated in an approved state plan, MWh generation from the unit could be used to adjust a CO 2 emission rate. Considerations for the use of biomass in state plans are discussed in section VIII.G.1.a(2)(c)(i). (c) Waste-to-energy. Use of qualifying biomass may include the biogenic portion of MSW combusted in a waste-to-energy facility. 670 With regard to assessing qualifying biomass specified in state plans, the EPA generally acknowledges the CO 2 emission reduction and climate policy benefits of waste-derived biomass, based on the conclusions supported by a variety of technical studies, including the revised Framework for Assessing

669 As with other RE, only generating capacity installed after 2012 would be eligible for use in adjusting a CO 2 emission rate. 670 As with other RE, only generating capacity installed after 2012 would be eligible for use in adjusting a CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 944 of 1275 Biogenic Carbon Dioxide for Stationary Sources. 671 Such wastederived biomass feedstocks would likely be approvable as qualifying biomass in a state plan. As described in Section VIII.G.1.a.(2)(c), states should propose qualifying biomass feedstocks and treatment of biogenic CO 2 emissions in state plans, along with supporting analysis, and the EPA would review the appropriateness and basis for such determinations in the course of its review of a state plan. Considerations for the use of biomass in state plans are discussed in section VIII.G.1.a.(2)(c)(i). 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-toenergy facilities or industrial facilities where the waste is combusted and energy is recovered. 672 Total MSW generation in 2012 was 251 million tons, but of that total volume generated, almost 87 million tons were recycled and composted. 673 Increasing demand for electricity generated from waste-to-energy facilities could increase competition for waste stream materials -

671 http://www.epa.gov/climatechange/downloads/Framework-forAssessing-Biogenic-CO2-Emissions.pdf. 672 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990- 2012. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport. html. 673 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 945 of 1275 including discarded organic waste materials, which could cause diversion of these materials from existing or future efforts promoting waste reduction, composting, and recycling. The EPA and many states have recognized the importance of integrated waste materials management strategies that emphasize a hierarchy of waste prevention and all other productive uses of waste materials to reduce the volume of disposed waste materials. 674 For example, Oregon and Vermont have strategies that emphasize waste prevention, followed by reuse, then recycling and composting materials prior to treatment and disposal. 675

Information in the revised Framework for Assessing Biogenic

CO 2 Emissions from Stationary Sources and other technical studies and tools (e.g., EPA Waste Reduction Model) should assist both states and the EPA in assessing the role of biogenic feedstocks used in waste-to-energy processes, where use of such feedstocks is included in a state plan. 676When developing their plans, states planning to use wasteto-energy as an option for the adjustment of a CO 2 emission rate should assess both their capacity to strengthen existing or implement new waste reduction, reuse, recycling and composting

674 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm. 675 http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

. 676 http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 946 of 1275 programs, and measures to minimize any potential negative impacts of waste-to-energy operations on such programs. States must include that information in their plan submissions. Only electric generation at a waste-to-energy facility that is related to the biogenic fraction of MSW and that is added after 2012 is eligible for use in adjusting a CO 2 emission rate. Total electric generation from the facility must be prorated based on the proportion of biogenic content of MSW. This can be achieved through periodic sampling of the biogenic fraction of the MSW used as fuel at a waste-to-energy facility, or based on the proportion of biogenic CO 2 emissions to total CO 2 emissions from the facility. Measuring the proportion of biogenic to

fossil CO 2 emissions can be performed via ASTM D-6866-06 testing or other methods (ASTM, 2006; Bohar, et al. 2010).For example, where the biogenic fraction of MSW is 50 percent by weight, only the proportion of MWh output attributable to the biogenic portion of MSW at the waste-to-energy facility may be used to adjust an affected EGU CO 2 emission rate. Alternatively, where biogenic CO 2 emissions represent 50 percent of total reported CO 2 emissions, a facility would need to estimate the fraction of biogenic to fossil MSW utilized and the net energy output of each component (based on relative higher heating values) to determine the percent of the MWh output from the waste-to-energy*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 947 of 1275 facility that may be used to adjust an affected EGU CO 2 emission rate. A state plan must propose 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 2 emission

rate. Where biogenic CO 2 emissions as a proportion of total CO 2 emissions from a waste-to-energy facility are used to prorate total MWh output that may be used to adjust a CO 2 emission rate, the state plan must specify requirements for reporting biogenic

CO 2 emissions from the facility. Reporting requirements for biogenic CO 2 emissions under 40 CFR 98 (§§ 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) are an acceptable default reporting approach that would be approvable. However, the EPA may approve other approaches included in a state plan. The EPA received multiple comments supporting the use of waste-to-energy as part of a state’s plan for reducing CO 2 emissions. Some commenters expressed concern that non-biogenic materials, such as plastics and metal, would be incinerated along with biogenic materials. As discussed above, only electricgeneration related to the biogenic fraction of MSW at a wasteto-energy facility added after 2012 is eligible for use in adjusting a CO 2 emission rate. The EPA also received comments that expressed concern about the potential negative impacts on*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 948 of 1275 recycling and waste reduction efforts, while other commenters asserted that waste-to-energy practices encourage recycling programs. Some commenters also expressed concern about what treatment would be approvable for emissions from waste-to-energy practices. As discussed above, potential negative impacts from waste-to-energy production on recycling, waste reduction, and composting programs should be evaluated and efforts to mitigate negative impacts must be discussed in state plans. (4) Demand-side management. Avoided MWh of electricity use that result from demand-side management may be used to adjust a CO 2emission rate. Eligible DSM actions are those that are nonemitting and avoid, rather than shift, the use of electricity by an electricity end-user. 677 The MWh that may be used for such an adjustment are determined based on the MW of demand reduction multiplied by the hours during which such a demand reduction is achieved (MW of demand reduction x hours = MWh avoided). DSM measures must be appropriately quantified and verified, in accordance with requirements in the emission guidelines, as

discussed in section VIII.C.3.

677 An example is a utility direct load control program, such as those where customer air conditioning units are cycled during periods of peak electricity demand. Actions that shift electricity demand from one time of day to another are not eligible, as these measures do not avoid electricity use from the grid. Use of emitting generators as a DSM measure are also not eligible.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 949 of 1275 (5) Energy storage. Energy storage may not be directly recognized as an eligible measure that can be used to adjust a

CO 2 emission rate, because storage does not directly substitute for electric generation from the grid or avoid electricity use from the grid. 678 The electric generation that is input to an energy storage unit may be used to adjust a CO 2 emission rate, but the output from the energy storage unit may not. 679 However, energy storage can be used as an enabling measure that facilitates greater use of RE, which can be used to adjust a CO 2 emission rate. For example, utility scale energy storage may be used to facilitate greater grid penetration of RE generating capacity and can also be used to store RE generation that may have otherwise been shed in times of excess generating capacity. Likewise, on-site energy storage at an electricity end-user can

678 Energy storage depends on a generation source, either from a utility-scale EGU (e.g., a fossil EGU, a wind turbine, etc.) or a distributed generation source at an electricity end-user (e.g., a PV system installed at a building). 679 This approach focuses on counting the qualifying electric generation, which may be an input to an energy storage unit. Counting both the generation input to energy storage and the output from the energy storage unit would be a form of double counting. The electric generation that is stored may be counted; the subsequent output from the storage unit may not. Furthermore, it may be impossible in certain instances to determine the specific EGUs that supplied an energy storage unit, in some utility-scale applications of energy storage.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 950 of 1275 enable greater use of RE to meet on-site electricity demand. 680 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 2 emission rate). (6) Transmission and distribution measures. 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 2 emission rate. This includes T&D measures that reduce losses of electricity during delivery from a generator to an end-user (sometimes

680 For example, battery storage at a building with solar PV can enable the PV system to meet the building’s entire electrical load, by storing energy during times of peak PV system output for later use when the sun is not shining.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 951 of 1275

referred to as “line losses” 681 ) and T&D measures that reduce electricity use at the end-user, such as conservation voltage reduction (CVR). 682 The EPA received many comments in support of advanced energy technologies, including energy storage and transmission and distribution upgrades, and including these technologies in the suite of potential measures that states could consider for emission rate adjustments in their state plans. Comments pointed out that in addition to helping achieve emission standards, T&D efficiency improvements make the grid more robust and flexible, as well as delivering environmental benefits. In many parts of the country, grid operators,

681 T&D system losses (or “line losses”) are typically defined as the difference between electricity generation to the grid and electricity sales. These losses are the fraction of electricity lost to resistance along the T&D lines, which varies depending on the specific conductors, the current, and the length of the lines . The Energy Information Administration (EIA) estimates that national electricity T&D losses average about 6% of the electricity that is transmitted and distributed in the United States each year. 682 Volt/VAR optimization (VVO) refers to coordinated efforts by utilities to manage and improve the delivery of power in order to increase the efficiency of electricity distribution. VVO is accomplished primarily through the implementation of smart grid technologies that improve the real-time response to the demand for power. Technologies for VVO include load tap changers and voltage regulators, which can help manage voltage levels, as well as capacitor banks that achieve reductions in transmission line loss. VVO efforts are often closely related to conservation voltage reduction (CVR), which are actions taken to reduce initial delivered voltage levels in feeder transmission lines while remaining within the 114 volt to 126 volt range required at the customer meter (based on ANSI C84.1 standards).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 952 of 1275 transmission planners, transmission owners and regulators are already taking steps to expand and modernize T&D networks. Commenters suggested that the EPA clarify the eligibility and criteria under which such measures would be permitted in a state plan. For T&D measures, the same eligibility date for measure installation applies as that which applies to demand-side EE installed after 2012. This general eligibility requirement is discussed above in section VIII.C.1.b.(2)(b). 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.C.3. To this point, the predominant view expressed in public comments was broad acknowledgement that EM&V for T&D strategies is maturing in tandem with their increasing adoption by states and utilities. For example, several commenters referenced protocols and procedures currently under development and already in usage for quantifying MWh savings from CVR. This development in EM&V for T&D strategies was cited as a rationale for their inclusion as an eligible measure that can be used to adjust a CO 2 emission rate. (7) Water system efficiency. Water efficiency programs that improve EE at water and wastewater treatment facilities also provide demand-side EE savings opportunities. The EPA received*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 953 of 1275 comments supporting the use of water sector EE programs and projects. Commenters identified water and wastewater utilities as particularly well-suited for participating in EE programs and providing a source of electricity savings. Investments such as replacing pumps and other aging equipment and repairing leaks can result in greater EE. The EPA agrees that these electricity savings should be eligible for adjustments to CO 2 emission rates

at affected EGUs. For water efficiency measures, the same eligibility date for measure installation applies as that which applies to demand-side EE--installed after 2012. This general eligibility requirement is discussed above in section VIII.C.1.b.(2)(b). The MWh of avoided electricity use that result from water efficiency measures must be appropriately quantified and verified, as

discussed in section VIII.C.3. (8) Nuclear power. As is discussed in section V.A.3., upon consideration of comments received, the EPA does not include either nuclear generation from 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 eligible measure that can be used to adjust a CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 954 of 1275

Commenters also recommended that the EPA consider nuclear generating units and RE generating units in a consistent manner

for CO 2 emission rate adjustments in state plans. We agree with comments that nuclear generation and RE should be treated consistently when it comes to CO 2 emission rate adjustments. 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 2 emission rate. However, consistent with the reasons discussed for not including the preservation of existing nuclear capacity in the BSER – namely, that such preservation does not actually reduce existing levels

of CO 2 emissions from affected EGUs – preserving generation from existing nuclear capacity is not eligible for use in adjusting a

CO 2 emission rate. In contrast, any incremental zero-emitting generation from new nuclear capacity would be expected to replace generation from affected EGUs and, thereby, reduce CO 2 emissions; and the continued commitment of the owner/operators to completion of the new units and improving the efficiency of existing units through uprates can play a key role in state plans. Therefore, consistent with treatment of other low- and zero-emitting generation, new nuclear power generating capacity installed after 2012 and incremental generation resulting from nuclear*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 955 of 1275 uprates after 2012 are measures eligible for adjusting a CO 2 emission rate. Additionally, existing nuclear units (i.e., those that originally commenced operation in 2012 or earlier years) that receive operating license extensions are not eligible for use in adjusting a CO 2 emission rate, except where such units receive a capacity uprate as a result of the relicensing process. Only the incremental capacity from the uprate is eligible for use to adjust a CO 2 emission rate. Applicable generation (in MWh) from incremental nuclear power is determined

in the same manner as that described for incremental hydroelectric power above. (9) CHP units. Electric generation from non-affected CHP units 683 may be used to adjust the CO 2 emission rate of an affected EGU, as CHP units displace emissions from an on-site boiler and electricity from the grid. Non-affected CHP units that meet the eligibility criteria under section VIII.G.1.b.(2) can be

683 The accounting treatment described in this section is for a “topping cycle” CHP unit. A topping cycle CHP unit refers to a configuration where fuel is first used to generate electricity and then heat is recovered from the electric generation process to provide additional useful thermal and/or mechanical energy. A CHP unit can also be configured as a “bottoming cycle” unit. In a bottoming cycle CHP unit, fuel is first used to provide thermal energy for an industrial process and the waste heat from that process is then used to generate electricity. Some WHP units are also bottoming cycle units and the accounting treatment for bottoming cycle CHP units is provided with the WHP description below.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 956 of 1275 considered under this option. In most cases, a CHP unit would be a low-emitting CO 2 source and therefore the MWh output would need to be prorated to account for the emissions. A denominator approach consistent with the accounting approach for EE and RE,

can be taken. The CHP unit’s electrical output would be prorated based on the

CO 2 emission rate of the electrical output associated with the

CHP unit. 684 The incremental rate would be relative to the applicable CO 2 emission rate for affected EGUs in the state and

would be limited to values between 0 and 1. Prorated MWh = (1-incremental CHP emission rate/applicable affected EGU emission limit rate)* CHP MWh output

Where the ratio is limited to values between 0 and 1.

The CHP electrical emission rate is the net emission rate when the CHP unit’s thermal output emissions are deducted from

the CHP unit’s total emissions. It can be derived as follows [CHP fuel input * fuel emission factor – (UTO/boiler efficiency) * fuel emission factor]/CHP MWh Non-affected CHP units can use qualifying biomass fuels. As

684 The applicable CO 2 emission limit rate depends on the type of state plan being implemented. Where a state plan includes a single CO 2 emission limit rate for the fleet of affected EGUs, the applicable rate is the rate that applies to all affected EGUs. Where a state plan includes subcategorized rates for different categories of affected EGUs, the applicable rate is the rate that applies to affected NGCC EGUs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 957 of 1275 described in Section VIII.G.1.a.(2)(c), states should propose qualifying biomass feedstocks and treatment of biogenic CO 2 emissions in state plans, along with supporting analysis and quality control measures, and the EPA would review the appropriateness and basis for such determinations in the course of its review of a state plan. Considerations for qualifying biomass included in state plans are discussed in section VIII.G.1.a.(2).(c).(i). The measurement of the fuel and MWh output of the CHP unit are based on standard industry practice and discussed in section

VIII.G.d.5.

In order to determine the incremental CO 2 emission rate, a CHP unit would monitor requirements for CO 2 emissions and energy output. 685 The monitoring requirements are standard methods currently in use and the requirements would depend on the size

of the CHP units and the fuel used in the unit.

Non-affected CHP facilities 686 with electric generating capacity greater than 100 MW would follow the same monitoring and reporting protocols for CO 2 emissions and energy output as

685 Where a CHP unit uses biomass fuel, it must report both total CO 2 emissions and biogenic CO 2 emissions. Requirements for reporting biogenic CO 2 emissions are discussed in section VIII.G.1.a.(2)(c) above. 686 A CHP facility may consist of one or more electric generators.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 958 of 1275 are required for affected EGU CHP units. These requirements are

discussed in section VIII.F. For non-affected CHP facilities with electric generating capacity less than 100 MW, which use only natural gas and/or distillate fuel oil, the low mass

emission unit CO 2 emission monitoring and reporting methodology outlined in 40 CFR 75, or a similar fuel tracking and emission factor approach, is acceptable. For non-affected CHP facilities with an electric generating capacity less than 100 MW, which use all other fuels, the CO 2 emissions monitoring and reporting protocols for affected EGU CHP units would be used. These requirements are discussed in section VIII.G.5.

Most comments received on CHP recommended that the EPA explicitly call out how CHP can be accounted for in a state plan. Some commenters pointed out that without such a description, states would not be able to readily take advantage

of the CO 2 emissions reduced by the use of CHP. Other commenters weighed the advantages to considering a numerator-based approach versus a denominator-based approach. The EPA believes that a denominator approach is appropriate because it is consistent with the accounting approach used for RE and demand-side EE. (10) WHP. WHP units that meet the eligibility criteria under section VIII.G.1.b.(2) may be used to adjust the CO 2 emission rate of an affected EGU. There are several types of WHP units.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 959 of 1275 There are units, also referred to as bottoming cycle CHP units, where the fuel is first used to provide thermal energy for an industrial process and the waste heat from that process is then used to generate electricity. 687 Emissions from these WHP facilities would be based on the initial fuel combustion process that produced the waste heat and would be accounted in the same way as non-affected CHP units under section VIII.G.1.b.9.

There are WHP facilities where the waste heat from the initial combustion process is used to generate additional power. There is no additional fuel used to generate this additional power as so there are no incremental emissions associated with that additional power. As a result, the incremental electric generation output from the WHP facilities could be considered non-emitting and the MWh of electrical output used to adjust the

CO 2 emission rate of an affected EGU.

Most commenters noted the benefits for WHP at the same time they discussed the benefits of CHP. The commenters reflected that WHP is another compliance option and requested it be called out explicitly as a compliance option. The comments discussed WHP benefits but did not elaborate on a preferred accounting

687 This configuration is sometimes referred to as a “bottoming cycle” CHP unit. In such a configuration, the waste heat stream could also be generated from a mechanical process, such as at natural gas pipeline compressors.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 960 of 1275

method. c. Measures that may not be used to adjust a CO 2 emission rate. This section addresses measures that may not be used to adjust a

CO 2 emission rate. Other new and existing non-affected fossil fuel-fired EGUs that are not subject to CAA section 111(b) or 111(d) may not be used to adjust the CO 2 emission rate of an affected EGU. While generation from such units could substitute for generation from affected EGUs, the EPA has determined that additional incentives for such generation, in the form of an explicit adjustment to the CO 2 rate of an affected EGU, are not necessary or warranted. Providing for such an adjustment could create perverse incentives for the construction of new simple cycle CTs that are not subject to the applicability criteria of

final Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units rule. For example, such units could provide only limited adjustment credit, as operation beyond a certain capacity factor threshold would trigger applicability under CAA section 111(b). Further, providing for the ability to generate adjustment credits would provide incentives for construction of less efficient fossil generating capacity than would likely otherwise be constructed (e.g., addition of a simple cycle combustion turbine rather than a NGCC unit). In addition, providing for the ability to generate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 961 of 1275 adjustment credits could create perverse incentives for the continued operation of less efficient existing fossil generating capacity. Such outcomes run counter to the objectives of this

final rule.

d. Measures that reduce CO 2 emissions outside the electric power

sector. Measures that reduce CO 2 emissions outside the electric power sector may not be counted toward meeting a CO 2 emission performance level for affected EGUs or a state CO 2 goal, under either a rate-based or mass-based approach, because all of the

emission reduction measures included in the EPA’s determination

of BSER reduce CO 2 emissions from affected EGUs. Examples of measure that may not be counted toward meeting a CO 2 emission performance level for affected EGUs or a state CO 2 goal include GHG offset projects representing emission reductions that occur in the forestry and agriculture sectors, 688 direct air capture, and crediting of CO 2 emission reductions that occur in the transportation sector as a result of vehicle electrification.

688 We note, however, that the final emission guidelines allow state measures like emission budget trading programs to include out-of-sector GHG offsets. For example, both the California and RGGI programs allow for the use of allowances awarded to GHG offset projects to be used to meet a specified portion of an affected emission source’s compliance obligation. The RGGI program contains a cost containment allowance reserve that makes available additional allowances up to a certain amount, at specified allowance price triggers. See section VIII.C.3.b(2)(a) of this preamble.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 962 of 1275

2. Treatment of interstate effects In the June 2014 proposal, the EPA acknowledged that emission reduction measures implemented under a state plan will likely have impacts across state boundaries due to the interstate nature of the electric grid, as is discussed above in section VIII.G. These interactions, herein called interstate effects, 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 non-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 state borders. EGUs are dispatched both within and across state borders and are constantly adjusting behavior in response to generation and electricity demand on the regional grid.

Whenever CO 2 emission reduction measures, such as RE or demandside EE, are implemented, the RE or demand-side EE can affect EGU generation and CO 2 emissions across the regional grid. Thesedynamics can change across multiple affected EGUs on a minuteto-minute, hour-to-hour, and day-to-day basis as electricity demand changes and different generating resources are dispatched. These dynamics will also change in the long-term, as the generating fleet and load behavior change over a period of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 963 of 1275 years. Interactions among states may be further driven by the plan types (i.e., rate-based or mass-based) and the individual characteristics of the plans that states choose to adopt. In the context of this complex environment of state policies and interstate grids, commenters expressed concern about the risk of double-counting of measure impacts across states and the potential for distortionary incentives between

states that could undermine overall CO 2 emission reductions (i.e., emissions “leakage”). Commenters requested that the EPA ensure that states avoid double-counting when demonstrating achievement of state goals and minimize leakage effects. The EPA acknowledges that some amount of interstate effects will inevitably be present and unavoidable in the context of this rule and may affect how affected EGUs achieve the applicable CO 2 performance rates or state goals under a state plan. The EPA has incorporated elements into the rule that seek to minimize interstate effects. First, states have the option to adopt multi-state compliance that reflects regional interactions. Second, in the method for rate-based plan compliance, the rule provides a general accounting approach for adjusting a source or state’s CO 2 rate that inherently acts to minimize state differences. Third, the final CO 2 performance rates uniformly apply the same standard for affected source*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 964 of 1275 sectors across the states and also account for the regional supply of RE available to states. These points are further

discussed below. For both rate-based and mass-based approaches, the rule provides states with the option of creating either multi-state plans or trading-ready plans. Both strategies can be effective in minimizing interstate effects because the regional impacts of emission reduction actions across states contribute to meeting aggregate rate-based or mass-based CO 2 emission goals. Under all types of state plans, states must ensure that the

measures and associated CO 2 emission reductions counted as part of meeting their plan requirements are not duplicative of any measures that are counted by another state. Interstate effects make this more difficult because states may be responsible for the deployment of measures that have effects on generation and emissions beyond the state borders. 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 general accounting approaches for both mass-based and rate-based plans minimize the risk of double counting. Mass-based plans rely exclusively on reported stack*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 965 of 1275 emissions for determining whether a mass-based CO 2 emission goal is achieved. This means that under a mass-based plan any emission reduction measures that are implemented are automatically accounted for in reduced stack emissions of CO 2 from affected EGUs, which avoids concerns about counting the

same mass reductions in two different states. In a rate-based plan, there needs to be an explicit adjustment of reported CO 2 emission rates from affected EGUs, to reflect the measures that substitute low- or zero-emitting generation or energy savings for affected EGU generation. Stateswith rate-based plans must demonstrate that the RE and demandside EE that they use to adjust their CO 2 emission rate are nonduplicative. The proposal attempted to address this issue inpart by limiting demand-side EE that states could claim to instate measures. In fact, those in-state measures still have an impact outside of the state and states are restricted from taking credit for all the measures they have put in place that

reduce CO 2 emissions. Therefore, the EPA is finalizing a

treatment that allows states to count all in-state and out-ofstate measures, while addressing interstate effects through the structure of its accounting approach for adjusting the CO 2 emission rate of an affected EGU, detailed in section VIII.C.1 above, used to show that the state has met its obligation under*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 966 of 1275 its state plan. The general accounting approach for adjusting the CO 2 emission rate of an affected EGU inherently accounts for the regional nature of how substitute generation and energy savings will impact affected EGU generation and CO 2 emissions. The following discussions refer to the substituting generation and energy savings in question as RE and demand-side EE, but this method can apply to other non-BSER technologies that substitute for affected EGU generation. The adjusted CO 2 emission rate gives

credit to the affected EGU or state for the MWhs of RE and demand-side EE it is responsible for deploying, by allowing

those MWhs to be added to the denominator of the CO 2 rate, but makes no adjustment to the numerator. Instead, the numerator reflects reported stack emissions, which will reflect the extent

to which RE and demand-side EE reduced the affected EGU’s generation and emissions, without needing to account for the state in which the RE or demand-EE originated, or exactly how it impacted the regional grid. Across states with rate-based plans, the accounting method avoids potential double-counting of both components of a CO 2 emission rate: CO 2 emission reductions and generation. Doublecounting of CO 2 emission reductions is prevented because there is no explicit adjustment to the numerator of the reported CO 2*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 967 of 1275

emission rate that could be redundant to CO 2 emission reductions already represented in reported CO 2 emissions from the affected EGU, resulting in double-counting. 689 Double-counting of MWhs in the denominator can be avoided because adding the MWh that the affected EGU is responsible for deploying to the denominator is relatively straightforward to quantify and assign, and 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 state, as is outlined in section VIII.C.2, then there is no double-counting of MWh. Therefore, the accounting method avoids double counting

of both CO 2 emission reductions and MWhs, the two characteristics

of RE and demand-side EE measures that affect CO 2 emission rates.There may also be interactions between mass-based and ratebased 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 2 performance rates or state goals. The EPA received comments on this particular issue, and many expressed concerns that this use of

689 If a MWh of substitute generation or avoided generation replaced generation at another affected EGU, CO 2 emission reductions would be represented in reduced reported CO 2 emissions from that affected EGU. Again, a double-counting of emission reduction effects would occur.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 968 of 1275

mass-based resources in a rate-based state would result in double-counting of emission reductions. 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 2 emissions from affected EGUs under either ratebased or mass-based state plans in order to eliminate doublecounting. 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 2 emission reductions associated with counting measures located in mass-based states, considering the accounting methods outlined in this final rule. First, as discussed above, the accounting method for adjusting the CO 2 emission rate only counts the MWhs generated by a measure to adjust the MWh in the denominator of its reported CO 2 emission

rate. The CO 2 emissions impacts of the measures will be reflected in the rate-based state only to the extent that the MWhs resulted in lower reported CO 2 emissions from an affected EGU in the rate-based state. To the extent that measures that provide substitute or avoided generation reduce generation from affected*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 969 of 1275 EGUs in a mass-based state, the effect of those measures is reflected in lower reported CO 2 emissions. The CO 2 emission

reductions reflected in the rate and the mass state will necessarily be mutually exclusive, because both are based on reported stack emissions. Additionally, the mechanism in the mass-based state that is assuring CO 2 emission reductions is the mass goal or cap, which is met by affected sources adjusting their generation. Low- or zero-emitting MWhs from resources like

RE and demand-side EE can serve load in the mass-based state and play a role in lowering compliance costs, but they play nodirect role in mass-based compliance. As a result, no doublecounting of emission reductions can take place. Though there is no risk of double-counting emissions, some commenters expressed the concern that overall CO 2 emissions

reductions would be eroded in situations where a source in a

rate-based state counts the MWh from measures in a mass-based state, but the generation from that measure acts solely to serve load in the mass-based state. As a result, expected CO 2 emission reduction actions in the rate-based state are foregone as a result of counting MWh that resulted in CO 2 emission reductions

in a mass-based state. While the EPA understands this concern, we do not believe it is appropriate to restrict RE and demand-side EE crediting*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 970 of 1275 unilaterally between rate-based and mass-based states. Such a restriction could cut some states off from regional RE supplies that are assumed in BSER building block 3 and incorporated in

the CO 2 emission performance rates or state rate-based CO 2 goals in the emission guidelines. Allowing crediting between rate- and mass-based states, as long as the risk of foregone CO 2 emission reduction actions in rate-based states are minimized, will assure a supply of eligible low- and zero-emitting MWhs that will further enable affected EGUs and states to meet obligations under the final rule. Therefore, the EPA has determined that it is appropriate for rate-based states to count MWhs from RE or demand-side EE measures, or similar low- or zero-emitting measures, located in mass-based states only if the measure isimplemented to meet electricity load in a state with a ratebased plan. 690 To assure that measures used to adjust a CO 2 emission rate meet this condition, the EPA is requiring thatmeasures providing zero- or low-emitting generation from nonaffected EGUs located in a mass-based state, such as RE, can only be counted if the energy generated is delivered to meet load in a state with a rate-based plan. This can be demonstrated through, for example: 1) the provision of a power delivery

690 This does not need to necessarily be the state where the MWh of energy generation from the measure is used to adjust the CO 2 emission rate of an affected EGU.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 971 of 1275 contract or power purchase agreement in which an entity in the rate-based state contracts for the supply of the mass-based MWhs in question and 2) documentation that this was done specifically to serve rate-based state load. The EPA is providing flexibility to states regarding the nature of the required demonstration, though the state must specify eligible demonstrations for approval in state plans. Under an emission standards plan, this demonstration would be made by the provider of the measure seeking ERC issuance tothe rate-based state. Under a state measures plan, the ratebased state will need to provide the demonstration of geographic eligibility as part of its demonstration that it is meeting its

CO 2 emission performance rates or achieving the state CO 2 emission goal for affected EGUs. The following are examples of how requirements for a demonstration could be established in state plans and used to

allow a resource in a mass-based state to be counted in a ratebased state. For an emissions 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 a provider of RE that seeks the issuance of ERCs to show that

entities in the rate-based state have contracted for the delivery of the RE generation that occurs in a mass-based state*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 972 of 1275 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 energy savings were procured by the utility, and were treated as comparable to 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 the additional geographic eligibility requirement for generation of ERCs. All quantified

and verified 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 monitoring and verification reports submitted for issuance of ERCs. Under a state measures rate-based plan, a state could require that any eligible MWhs that the state claims from a mass-based state are the result of contracted arrangements between entities in the rate-based state and providers in the mass-based state. If the state plan was approved by the EPA,

such demonstrations would need to be submitted with the state’s

demonstration of how its state measures meet the CO 2 emission performance rates or achieve the state rate-based CO 2 emission goal for affected EGUs. The ability for a rate-based state to count MWhs located in*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 973 of 1275

a mass-based state under the above conditions is limited to nonaffected generating resources that are considered low- or zeroemitting, such as RE. This treatment does not apply to fossilfuel fired EGUs, such as NGCC. If a mass-based emission limit has been applied to an affected EGU, there is no valid way to calculate whether it has MWh that are eligible for crediting, as is possible under a rate-based plan. As stated earlier, commenters also expressed concern about the potential for a loss of emission reductions to occur given

relative differences between 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 building new generation and expanding utilization of affected EGU generation in states that have less stringent goals. This could potentially result in the achievement of performance rates but with fewer overall CO 2 emissions reductions than projected nationally under the proposal. In order to address these concerns, the EPA has determined final performance rates that serve to reduce relative*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 974 of 1275 differences between state goals, and thus the risk of leakage based upon those effects. In the proposal, goals differed significantly between states based upon individual assumptions included in the calculation. In the final rule, we are finalizing CO 2 emission performance rates for fossil fuel-fired electric utility steam generating units and stationary combustion turbines that are applied consistently across all affected EGUs. Additionally, these finalized performance rates were calculated regionally, further narrowing the differences across states. As the same sector performance rates are applied to all states, any differences stem from the relative prevalence of fossil fuel-fired electric utility steam generating units and stationary combustion turbines. Commenters also suggested that the 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. 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-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 975 of 1275 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 nature of the accounting method finalized in this rule. As explained above on the general accounting approach and on 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 tradingmethods minimize the relative incentives for generating zeroemitting ERCs in a particular state based upon the rates that apply to that state. 3. Requirements for rate-based emission trading approaches As with all approaches under the emission standards plantype, emission standards in a state plan that include a ratebased emission trading program must be quantifiable, verifiable,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 976 of 1275 enforceable, non-duplicative and permanent. 691 A state plan using a rate-based emission trading approach must include emission standards for affected EGUs that include requirements specifying the rate-based emission standards and related implementation and compliance requirements and mechanisms. 692 These related requirements include those applicable to rate-based emission standards more broadly: CO 2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs, including requirements for monitoring and reporting of useful energy output. Related requirements for a rate-based emission trading program more specifically include provisions for issuance of ERCs by the state and/or its designated agent; provisions for tracking ERCs, from issuance through submission for compliance; and the administrative process for submission of ERCs by the owner or operator of an affected EGU to the state, in order to adjust its reported CO 2 emission rate when demonstrating compliance with a rate-based emission standard. 693 These requirements specific to rate-based emission trading programs are design elements the EPA has determined are necessary to

691 These requirements are described in detail in section VIII.D.2. 692 As described below, these requirements would likely be provided in a state plan in the form of state regulations, but could potentially be provided in another form. 693 See section VIII.G.1 for a discussion of the accounting method used to adjust a CO 2 emission rate.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 977 of 1275 assure the integrity of a rate-based approach that includes an emission trading program, and therefore assures a state plan utilizing such an approach appropriately provides for the implementation of rate-based emission standards in accordance with CAA section 111(d). The EPA will review a state plan submittal including a rate-based emission trading program to assure that the plan contains the design elements necessary to assure the integrity of a rate-based approach, and therefore provide for the implementation of rate-based emission standards. These design elements are discussed in more detail in this subsection, and the EPA for each design element has also provided what it views as an appropriate way for states to meet each such element so as to provide for the implementation of rate-based emission standards through an emission trading program. The EPA expects that state plans containing a rate-based emission trading program that includes components as substantively described for each of the design elements will be presumptively approvable (so long as the rate-based emission standards are also appropriately

demonstrated to achieve the CO 2 emission performance rates or

state CO 2 goal). States may submit a rate-based emission trading program with alternative components other than those described, so long as the program includes each of the required design*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 978 of 1275 elements and the state satisfactorily demonstrates in the state plan submittal that such alternative means of addressing the design elements are as adequately stringent as the presumptively approvable approach as described, and therefore provide for the implementation of the state plan’s rate-based emission

standards. A state may issue ERCs to an affected EGU that performs at

a CO 2 emission rate below a specified CO 2 emission rate, as well as to providers of qualifying measures that provide substitute generation for affected EGUs or avoid the need for generation from affected EGUs. This latter category includes providers of qualifying RE and demand-side EE measures, as well as other types of measures, as discussed in section VIII.G.1.b. 694 ERCs may be used by an affected EGU to adjust its reported

CO 2 emission rate when demonstrating compliance with a rate-based emission limit. This adjustment is made by adding MWh to the denominator of an affected EGU’s reported CO 2 emission rate, in the amount of submitted ERCs, resulting in a lower adjusted

694 As used in this section, the term “EE program” refers to an EE deployment program. An EE program involves deployment ofmultiple EE measures or EE projects, such as utility- or stateadministered EE incentive programs that accelerate the deployment of EE technologies and practices. As used in this section, the term “EE/RE project” refers to a discrete EE project (e.g., an EE upgrade to a commercial building or set of buildings) or a RE generator (e.g., a single wind turbine or group of turbines).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 979 of 1275 rate. To demonstrate compliance with a rate-based emission standard, an affected EGU would report its CO 2 lb/MWh emission rate to the state regulatory body, and would also surrender to the state any ERCs it wishes to use to adjust its reported emission rate. The state regulator would then cancel the submitted ERCs and add the MWh the ERCs represent to the denominator of the affected EGU’s reported CO 2 lb/MWh emission rate. If the affected EGU’s adjusted CO 2 emission rate is equal to or lower than its applicable emission rate standard, the affected EGU would be in compliance. a. Issuance of ERCs to affected EGUs. ERCs may be issued to affected EGUs that emit below a specified CO 2 emission rate. For issuance of ERCs to affected EGUs, the state plan must specify the accounting method and administrative process for ERC issuance. This includes the calculation method for determining the number of ERCs to be issued to an affected EGU, based on reported CO 2 emissions and MWh energy output, in comparison to a

reference CO 2 emission rate. The reference rate is a specified

CO 2 lb/MWh emission rate that an affected EGU’s reported CO 2 emission rate is compared to, when determining the amount of ERCs that may be issued to an affected EGU. Following determination of the number of ERCs an affected EGU is eligible to receive, based on an affected EGU’s reported*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 980 of 1275

CO 2 emission rate compared to a specified reference rate, the state regulatory body would issue those ERCs into a tracking system account held by the owner or operator of the affected EGU. Tracking system requirements are addressed below at section

VIII.G.3.c. 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 (e.g., if a plan is designed to meet a state rate-based CO 2 goal) or separate rate-based emission standards that apply to subcategories of affected EGUs, namely fossil fuel-fired electric utility steam generating units and stationary combustion turbines. In both cases, ERCs are issued in MWh, based on the difference between an affected EGU’s reported CO 2 emission rate (in CO 2 lb/MWh) and a specified CO 2 lb/MWh emission rate that the reported rate is compared to (referred to as a “reference rate”). The reference rate may be an affected EGU’s assigned CO 2 emission limit rate or another CO 2 emission rate, as described below. Where an affected EGU’s reported CO 2 emission rate is lower than the specified reference CO 2 emission rate, ERCs may be issued. Where a state plan includes emission standards in the form of a single rate-based emission standard that applies to all*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 981 of 1275 affected EGUs, the reference rate is the CO 2 emission rate limit for affected EGUs. In this instance, ERCs may be issued based on an affected EGU’s reported CO 2 emission rate as a proportion of the emission limit rate. For example, if the emission rate limit is 2,000 lb CO 2 /MWh and the affected EGU emits at a rate of 1,000

lb CO 2 /MWh, 0.5 MWh would be awarded for every MWh generated by

the affected EGU. ERCs would be issued to affected EGUs in whole

MWh increments. The calculation method is as follows:

ERCs 695 = reported MWh by affected EGU 696 x ((CO 2 emission

rate limit for affected EGUs 697 – affected EGU reported CO 2 emission rate 698 )/ CO 2 emission rate limit for affected EGUs) For the example above, the calculation is as follows: ERCs = MWh reported x (2,000 – 1,000)/2,000 = MWh reported

x 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

695 For all calculations in this section, where the result is a negative value, no ERCs would be issued. 696 This term represents the reported MWh by the affected EGU on an annual basis. 697 This term represents the “reference rate.” 698 This term represents the annual reported CO 2 emission rate of the affected EGU.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 982 of 1275 stationary combustion turbines, the reference rate differs for affected fossil fuel-fired electric utility steam generating units and stationary combustion turbines. For affected steam generating units, the reference CO 2 emission rate is the assigned CO 2 emission rate limit for steam generating units. For affected steam generating units, the following accounting method for generating ERCs applies:

ERCs 699 = reported MWh x ((steam generating unit CO 2 emission

rate limit 700 – steam generating unit reported CO 2 emission rate)/ steam generating unit CO 2 emission rate limit). For affected stationary combustion turbines, the reference

CO 2 emission rate differs for “non-incremental” generation and “incremental” generation from the affected stationary combustion turbine. Incremental generation by an affected EGU is defined as annual energy generation, in MWh, that is greater than reported MWh generation by the EGU in 2012. For example, assume an affected stationary combustion turbine generated 1,000,000 MWh in 2012 and 1,100,000 MWh in 2022; the stationary combustion turbine’s incremental generation in 2022 is 100,000 MWh and its non-incremental generation is 1,000,000 MWh.

699 For all calculations in this section, where the result is a negative value, no ERCs would be issued. 700 The “reference rate.”*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 983 of 1275 For affected stationary combustion turbines, the following accounting method for generating ERCs applies for nonincremental generation: ERCs = reported MWh x ((stationary combustion turbine CO 2 emission rate limit 701 – stationary combustion turbine reported

CO 2 emission rate)/ stationary combustion turbine CO 2 emission rate limit) Under this approach, ERC issuance is assessed based on the

difference between the CO 2 emission rate limit for affected stationary combustion turbines 702 and the reported CO 2 emission rate of the affected stationary combustion turbine. For affected stationary combustion turbines, the following accounting method for generating ERCs applies for incremental generation: ERCs = reported MWh x [((steam generating unit CO 2 emission

rate limit 703 – stationary combustion turbine reported CO 2 emission rate)/ steam generating unit CO 2 emission rate limit) + ((stationary combustion turbine CO 2 emission rate limit 704 - stationary combustion turbine reported CO 2 emission rate)/ stationary combustion turbine CO 2 emission rate limit)]

701 The “reference rate.” 702 This is the CO 2 emission performance level for affected stationary combustion turbines in the emission guidelines. 703 The “reference rate.” 704 The “reference rate.”*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 984 of 1275 Under this approach, ERC issuance is assessed based in part

on the difference between the CO 2 emission performance level for fossil steam generating units and the reported CO 2 emission rate of the affected stationary combustion turbine. The calculation also accounts for the difference in an affected stationary combustion turbine’s reported CO 2 emission rate and the CO 2 rate limit for affected stationary combustion turbines. 705 This avoids over-crediting where an affected stationary combustion turbine emits above its assigned CO 2 emission rate limit. Overall, this

calculation method 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 2 emission rate limit for the entirety of its MWh energy output. For example, assume an affected stationary combustion

turbine with a CO 2 emission rate of 800 lb CO 2 /MWh; a stationary

combustion turbine CO 2 emission rate limit of 700 lb CO 2 /MWh; and a steam generating unit CO 2 emission rate limit of 1,300 lb

CO 2 /MWh. For every incremental MWh of reported energy generation

705 This is the CO 2 emission performance level for affected stationary combustion turbines in the emission guidelines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 985 of 1275 by an affected stationary combustion turbine, ERCs would be issued in the following amount: ERCs = reported incremental MWh x [(1,300 – 800)/1,300 + (700 – 800)/700] = reported incremental MWh x [0.38 + (-0.14)] = reported MWh x 0.24 706 Thus, for every incremental MWh of reported energy generation by an affected stationary combustion turbine, 0.24 ERCs would be generated. ERCs would be issued in whole MWh

increments. These accounting requirements maintain consistency with the EPA’s application of BSER when calculating CO 2 emission performance rates for affected stationary combustion turbine and steam generating units. In particular, this accounting treatment maintains consistency of accounting in a state rate-based CO 2 emission standard with the EPA’s application of building block 2 in calculating CO 2 emission performance rates for affected fossil

706 This calculation accounts for incremental generation from the affected stationary combustion turbine, while acknowledging that stationary combustion turbine generation is low-emitting, but not non-emitting. The calculation also acknowledges that in this instance, the affected stationary combustion turbine’s reported CO 2 emission rate is higher than its applicable emission rate limit. As a result, for every MWh of generation, the stationary combustion turbine accrues a compliance debit that must be metthrough submission of ERCs. This calculation avoids overcrediting for incremental generation by affected stationary combustion turbines, where an affected stationary combustion turbine emits above its assigned CO 2 emission rate limit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 986 of 1275 fuel-fired electric utility steam generating units and stationary combustion turbines, which is based on use of incremental generation from affected stationary combustion turbine to replace generation from affected steam generating

units. b. Issuance of ERCs for RE, demand-side EE, and other measures. ERCs may be issued for qualifying measures. 707 For issuance of ERCs for qualifying measures, state plan requirements for ERC issuance must include a two-step process. In the first step of the process, a potential ERC provider submits an eligibility application for a qualifying program or project 708 to the administering state regulator (or its agent 709 ). The state regulator reviews the application to determine whether, in this example, an EE/RE program or project meets eligibility

707 Qualifying measures that can be used to adjust the CO 2 emission rate of an affected EGU are discussed at subsection VIII.G.1, and include RE, demand-side EE, and other measures, such as DSM, CHP and incremental nuclear generation. 708 For example, for an EE/RE program or project, as described in this section for illustrative purposes. The requirements described in this section for EE/RE programs and projects also apply for all other eligible qualifying measures discussed in subsection VIII.G.1. 709 As used here, an agent is a party acting on behalf of the state, based on authority vested in it by the state, pursuant to the legal authority of the state. A state could designate an agent to provide certain limited administrative services, or could choose to vest an agent with greater authority. Where an agent issues an ERC on behalf of the state, such issuance would have the same legal effect as issuance of an ERC by the state.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 987 of 1275 requirements for the issuance of ERCs. 710 An eligibility application must include a description of the program or project, a projection of the MWh generation or energy savings anticipated over the life of the program or project, and an EM&V plan that meets state requirements. The EM&V plan must describe how MWh of RE generation or energy savings resulting from the program or project will be quantified and verified. 711 A state, in its emission standard regulations, must include requirements for EM&V plans that are consistent with the requirements in the emission guidelines for EE/RE measures and other eligible measures, as discussed in section VIII.G.1 above, and section

VIII.C.4 below. The EPA has determined that state requirements for an eligibility application must include review of the application by an accredited independent verifier prior to submittal. This

710 The entity implementing the EE/RE program or project (referred to in the preamble as a “provider”) would submit the application. This is the identified entity to which ERCs would ultimately be issued, to a tracking system account held by the entity. Such entities could include a wide variety of parties that implement EE/RE programs and projects, including owners or operators of affected EGUs, electric distribution companies, independent power producers, energy service companies, and administrators of state EE programs, among others. 711 The verification process includes confirmation that quantified MWh are non-duplicative and permanent (i.e., are not being used in any other state plan to demonstrate compliance with an emission standard or achievement of a state CO 2 goal).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 988 of 1275 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. 712 An assessment by an accredited independent verifier would be included as a component of an eligibility application. 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 monitoring and verification reports are thoroughly reviewed prior to issuance of ERCs. Rate-based emission trading programs used in a state plan must include requirements for independent verifiers that specify necessary qualifications and codes of conduct when providing

712 Information about the verification process for GHG offsets under the RGGI program, including verifier accreditation requirements and access to relevant documents, is available at http://www.rggi.org/market/offsets/verification. Similar information about the verification process for GHG offsets under the California program is available at http://www.arb.ca.gov/cc/capandtrade/offsets/verification/verifi cation.htm.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 989 of 1275 verification services. State requirements must include accreditation requirements for independent verifiers that specify that only accredited verifiers may provide verification services and detail the requirements for accreditation and

maintenance of accreditation status. 713 These requirements must ensure that verifiers have sufficient knowledge of the rate-based emission trading program rules, technical expertise, and knowledge of auditing, accounting, and information management practices. Accredited verifiers must be independent. Accredited verifiers may not provide verification services for any ERC provider for which they have a financial, management, or other interest. 714 Such

713 In this subsection, the term “verifier” is used interchangeably to refer to both a “verification body” (i.e., a verification company or organization) and a “verifier,” which is an individual that is a principal or employee of a verification body. 714 Accredited verification bodies and individual verifiers may not have any direct or indirect organizational or personal relationships with an ERC provider that would impact their impartiality in assessing the validity and accuracy of the information in an eligibility application or M&V report. In addition to this general requirement, the following specific requirements also apply. Accredited verifiers must have no direct or indirect financial interest in, or other financial relationships with, an ERC provider or any related program or project that seeks issuance of ERCs. Accredited verifiers must have no relationship with the implementer of a program or project that seeks the issuance of ERCs, or any related ERC provider, that would represent a COI. Accredited verifiers must have no role in the development and implementation of a program or project that seeks issuance of ERCs, beyond the provision of*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 990 of 1275 relationships constitute a conflict of interest (COI). COI situations may also arise as a result of personal relationships among individuals representing an ERC provider and an accredited verifier. State requirements must specify that a verification report will not be accepted as part of an eligibility application or M&V report where the accredited verification body or any individual verifier has a COI. Accredited verification bodies must have management protocols in place to identify and remedy any COI prior to provision of verification services. State requirements should specify that failure of an accredited verifier to identify and adequately address any COI prior to provision of verification services is grounds for revocation of accreditation. State accreditation requirements should include periodic performance reviews by the administering state regulatory body of accredited verifiers, to ensure that verifiers are maintaining necessary technical and professional

verification services. Accredited verifiers must not be compensated, directly or indirectly, in relation to the quantified and verified MWh in an M&V report or on the basis of program or project approval, ERC issuance, or the number of ERCs issued. Accredited verifiers may not hold ERCs, or other financial derivatives related to ERCs, or have a financial relationship with other parties that hold ERCs or other related financial derivatives. Verification reports must include an attestation by the accredited verifier that it assessed potential COI related to an ERC provider and adequately addressed any identified COI.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 991 of 1275 qualifications and are meeting program requirements for provision of verification services. State accreditation requirements may recognize in part accreditation by an outside organization other than the state, where such outside accreditation demonstrates that certain state requirements are

met. 715 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. 716 These provisions will ensure that actions that are eligible for the issuance of ERCs are “non-duplicative.” 717 The tracking system used to administer a state’s rate-based emission trading system must provide transparent, electronic, public access to information about program and project eligibility applications, including EM&V plans, and regulatory approval status. In the second step of the process, following implementation

715 An example is ANSI accreditation under ISO 14065:2013 for GHG validation and verification bodies. More information is available at https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp?menuID =200. 716 This includes ensuring that multiple parties do not submit an eligibility application for the same EE program or project, or for the same RE generator. 717 Emission standards must be “non-duplicative” as described in section VIII.D.2.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 992 of 1275 of the RE/EE program or project, in this example, that was approved in step one, the RE/EE provider periodically submits a monitoring and verification (M&V) report to the state regulatory body documenting the results of the program or project in MWh of electric generation or energy savings. 718 These results are quantified according to the EM&V plan that was approved as part of step one. These results are verified by an accredited independent verifier, and its verification assessment must be included as part of the M&V report submitted to the state regulatory body. The administering state regulator (or its agent) then reviews the M&V report, and determines the number of ERCs (if any) that should be issued, based on the report. Finally, the state regulatory body (or its agent) issues ERCs to the provider of the approved program or project. These ERCs are issued to the tracking system account held by the program or project provider. State 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

718 State rate-based emission trading program regulations should specify the frequency for submission of monitoring and verification reports for approved qualified measures that have been deemed eligible to generate ERCs.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 993 of 1275 is submitted only once for each RE/EE action, and to only one state program. 719 The tracking system must provide transparent electronic public access to submitted M&V reports and regulatory approvals related to such reports. 720 Such reports are the basis

for issuance of ERCs. c. Tracking system requirements. 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” by the administering state regulatory body), 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, 721 and an accompanying tracking system infrastructure design based on business rules specified in the emission trading program regulations. Each issued ERC must have

719 EE/RE programs and projects, and other eligible measures, with an approved eligibility application would be designated in a tracking system as qualified programs or projects. Qualified programs and projects may be issued ERCs, based on approved M&V reports. 720 This must include electronic Internet access to such information in the tracking system. 721 “Compliance true-up” refers to ERC submission by an owner or operator of an affected EGU to adjust a reported CO 2 emission rate, and determination of whether the adjusted rate is equal to or lower than the applicable rate-based emission limit.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 994 of 1275 a unique identifier (e.g., serial number) and the tracking system must provide for traceability of issued ERCs back to the program or project for which they were issued.

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. Effect of improperly issued ERCs: Because the goal of this rulemaking is the actual reduction of CO 2 emissions, it is fundamental that ERCs represent the MWh of energy generation or savings they purport to represent. To this end, only valid ERCs that actually meet the standards articulated in this rule may be used to satisfy any aspect of compliance by an affected EGU with emission standards. Despite safeguards included in the structure of ERC issuance and tracking systems, such as the review of eligibility applications and M&V reports, and state issuance of ERCs, ERCs may be issued that do not, in fact, represent eligible zero-emission MWh as required in the emission guidelines. A variety of situations may result in such improper*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 995 of 1275 ERC issuance, ranging from simple paperwork errors to outright

fraud. It is thus essential that the ultimate responsibility for the validity of the ERC rest with the entity that must achieve compliance with an emission standard. 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 use properly issued, valid ERCs to demonstrate compliance with its emission standard. An EGU that submits for compliance with its emission standard an ERC that does not actually represent an eligible MWh of zero-emission generation is subject to CAA liability for failure to meet its emission standard for each day of the relevant compliance period, and must submit two properly issued, valid replacement ERCs to the state regulatory body within a specified period of time, in accordance with the emission guidelines. This is true regardless of the good faith of the EGU in purchasing or obtaining the ERC. The state plan must also make clear that the EGU is also subject to CAA liability for failure to timely submit replacement ERCs.

e. Considerations for ERC issuance. The EPA notes that stateadministered and state-overseen EE programs, such as those administered by state-regulated electric distribution utilities,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 996 of 1275could play a key role in supplying energy savings to a ratebased 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 from a qualifying measure that may be used to adjust the reported CO 2 emission rate of an affected EGU subject to a ratebased emission standard in an approved state plan under CAA section 111(d). The sole purpose of an ERC is for use by an affected EGU in demonstrating compliance with a rate-based emission standard in such an approved state plan. An ERC is issued separately from any other instruments that*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 997 of 1275 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 (e.g., such as state RPS and EERS requirements) or for use in voluntary markets. An ERC may be issued based on the same data and verification requirements used by existing REC and EEC tracking systems for issuance of RECs and EECs. 4. Evaluation, measurement and verification (EM&V) requirements for RE and demand-side EE resources used to adjust a CO 2 rate

This section identifies and discusses the EM&V criteria used to quantify MWh savings from demand-side EE and generation from zero-emitting RE. 722 These criteria apply in the context of both emission standard plans and state measures plans, as described below. The EPA is finalizing these criteria as applicable requirements in the context of state plans that employ a rate-based emission trading program. These criteria are described below. State plans must require that MWh savings from demand-side EE and generation from zero-emitting RE are quantified per these criteria. 723

722 EM&V is defined to mean the set of procedures, methods, and analytic approaches used to quantify the MWh from demand-side EE and RE, and thereby ensure that the resulting savings and generation are quantifiable and verifiable. 723 For a rate based emission standards plan type, the requirement to quantify the MWh from demand-side EE and RE per*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 998 of 1275 Additionally, with respect to these criteria, the EPA describes certain established standard industry practices that would be presumptively approvable as an approach to include these criteria in state plans. States must submit these criteria as specified, or alternatively, states may submit the standard industry practices described as presumptively approvable. States may also submit other means of meeting the criteria so long as the state satisfactorily demonstrates in the state plan submittal that such alternative means of addressing criteria are as adequately stringent as the presumptively approvable approach

described here. As discussed in VIII.G.3., quantified and verified MWh of RE generation, and quantified and verified MWh avoided from implementing demand-side EE measures, 724 may be used to adjust a

CO 2 emission rate when demonstrating compliance with the emission

the EM&V criteria must be included in the federally enforceable state plan. For a state measures plan implementing rate based state measures, applicable state laws must reflect the requirement to quantify the MWh from demand-side EE and RE per the EM&V criteria, and such state only requirements must be adequately described in the supporting documentation submitted with the state plan. 724 In the context of demand-side EE, “measure” refers to an installed piece of equipment or system at an end-use energy consumer facility, a strategy intended to affect consumer energy use behaviors, or a modification of equipment, systems or operations that reduces the amount of energy that would otherwise have been used to deliver an equivalent or improved level of end-use service.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 999 of 1275 guidelines. In states implementing emission standard type plans with rate-based trading, affected EGUs adjust their reported emission rate using ERCs, which represent MWh that are quantified and verified according to the EM&V criteria included

in this section. Providers of EE and RE who seek to earn ERCs must develop EM&V plans outlining how they will quantify and verify the results of their efforts. These providers are then required to submit EM&V plans as part of their application to the state regulatory body for project approval. 725 In states implementing state measures type plans, quantified and verified MWh of RE and EE may be used to adjust an emission rate through two pathways. First, if the state measures plan enables rate-based trading, the affected EGUs may use ERCs to adjust their reported rate (per the rate-based emission standard approach). Alternatively, if the state measures plan elects to incorporate RE and demand-side EE outside of an ERC trading program – for example through adoption and implementation of an EERS or RPS – the state itself, rather than the project provider, uses the quantified and verified MWh of RE and EE to adjust the rate. If a state elects to implement a rate-based ERC trading

725 A full discussion of applicable requirements for the establishment and functioning of rate-based emissions trading systems is provided above, at section VIII.G.3.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1000 of 1275 program as part of its state measures approach, state regulations and project provider requirements must be identical to those outlined for emission standard plans. For a state measures plan, the ERC issuance and EM&V requirements must be adequately described in the submittal’s supporting materials to enable the EPA to determine whether the state measures plan satisfactorily demonstrates the ability of the affected EGUs to meet the applicable CO 2 emission performance rate or state goal. For an emission standards plan, the ERC issuance and EM&V requirements would be submitted as a component for approval as part of the federally enforceable state plan. However, if the state elects to incorporate demand-side EE and RE policies, programs, and projects outside of an ERC trading program, the state itself, rather than the project provider, must demonstrate how it will quantify and verify the results of its efforts. In this case, the state must describe in its state plan submission how the criteria described herein will be applied to specific programs and projects to demonstrate that reported annual MWh savings and generation are properly quantified and verified.The following discussion presents EM&V criteria for demandside RE and EE measures implemented through both types of state plan approaches, followed by a presentation of some additional considerations for states implementing RE and EE measures in the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1001 of 1275 context of a state measures plan without rate-based trading.

5. EM&V criteria for RE and demand-side EE resources used to adjust a CO 2 rate The proposed rule stated that the EPA would establish EM&V criteria to help states, sources, and RE and EE providers quantify and verify MWh savings and generation resulting from RE and demand-side EE efforts. The proposal and associated “State

Plans Considerations” TSD 726 suggested that the EPA’s EM&V criteria would leverage the industry-standard practices, protocols, and data-sets currently utilized by the majority of states currently implementing demand-side EE and RE programs. The EPA further noted that many state regulatory bodies and other entities already have significant EM&V infrastructure in place and have been applying, refining and enhancing their evaluation and associated quality assurance approaches for over 30 years. The EPA took comment on whether this infrastructure is appropriate to use as the basis for establishing minimum EM&V criteria for use in rate-based state plans that include RE and demand-side EE. The majority of commenters addressing this question indicated that existing EM&V infrastructure is

726 See discussion beginning on p. 34 of the State Plan Considerations TSD for the Clean Power Plan Proposed Rule:http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1002 of 1275 appropriate to assure quality, credibility, and integrity. Thus,

the final EM&V criteria reflected herein are intended to be consistent with and leverage prevailing industry-standard evaluation practices. In addition, the EPA’s final criteria reflect several overarching objectives and principles offered by states, private organizations, and the public during the comment period. One of these is the importance of striking a reasonable balance between EM&V rigor and credibility on the one hand, and the costs associated with performance evaluation on the other. Another objective for the EPA’s criteria is to avoid excessive interference with EM&V practices that are already robust, transparent and working well. Therefore, the minimum criteria for EM&V in an approvable state plan establish a floor for EM&V practices to ensure credibility and certainty in savings estimates across jurisdictions. a. Submittals. Applicable submittals include EM&V plans and EM&V reports. At the front end of a program or project, EM&V plans are required to document how applicable criteria will be addressed as EM&V is performed over the program or project period. After implementation has occurred, EM&V reports are required to document and describe how each of the criteria was applied on an ex-post basis. These reports also specify the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1003 of 1275 resulting MWh savings or generation values per RE and EE program and project category. For demand-side EE, EM&V plans and reports for purposes of this final rule are intended to leverage and closely resemble EM&V plans that are 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 tracking systems for RE that are broadly applied. EM&V reports for RE are simply the existing output from these tracking systems. For all EM&V submittals addressing demand-side EE, the applicable metric is electricity savings, which is defined as a reduction in electricity consumption. EE savings must be determined and reported in units of MWh. The specific procedures and requirements for EM&V submittals in the context of an emission standard plan are outlined above in section VIII.G.3. EM&V submittals for state measures plans are described below. b. EM&V criteria that apply to all demand-side EE used to adjust an emission rate. The following EM&V criteria apply to all demand-side EE used to adjust an emission rate. They are supplemented by the program and project specific provisions

identified below. (1) Baseline definitions. A critical EM&V issue is the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1004 of 1275 assumptions and approach used to determine baseline energy use. EM&V plans must describe the baselines to be used with clear documentation and discussion of the rationale, applicability, and relevant data sources, protocols, and guidance documents used for defining the baseline. (2) EM&V methods used to quantify the results of EE projects and programs. This section establishes criteria for the general types of EM&V methods that can EE providers can use to quantify savings from demand-side EE programs and projects that are used to generate ERCs. Consistent with EM&V practices at the state level, where PUCs typically allow utilities and other program administrators 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), the EPA is likewise providing flexibility for RE and EE providers to select from the following broad categories of EM&V methods to determine savings. Two broad categories of EM&V methods are non-control group approaches such as project-based measurement and verification*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1005 of 1275 (M&V), 727 and control group approaches 728 such as randomized control trials (RCT). Regardless of the approach selected, a keycriterion, supported by commenters and consistent with industrystandard practices, is that annual savings values must be determined on a regular basis – at intervals sufficient to credibly document annual savings – by application of one or more

of the above-listed EM&V methods. Factors that should be taken into consideration when determining the appropriate interval include the characteristics of subject EE programs, projects, or measures; variability of the savings; the EM&V method used; and the relative scale and magnitude of savings. The EPA expects that EM&V using the above methods will occur at a minimum of four year intervals for building energy codes and product standards; every one, two or three years for different publicly or rate-payer funded EE programs; and annually for largeindividual commercial and industrial projects. For all demandside EE used to adjust an emissions rate, the selected method, associated assumptions, and data sources must be identified and

727 M&V is the process of using measurements to reliably determine energy and/or demand savings created within an individual facility. The International Performance Measurement and Verification Protocol (IPMVP) defines four M&V options used in the efficiency industry: two end-use metering approaches, energy use data (billing data) regression analysis, and calibrated computer simulation. 728 Also referred to as large-scale consumption data analysis.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1006 of 1275 described in EM&V plans. For control group methods, the key EM&V criteria is to follow industry standard protocols and guidelines such as those published by the SEE Action Network and the U.S. DOE’s Uniform Methods Protocols (UMP) project. Where feasible, the EPA seeks to encourage the use of RCT approaches to establishing control groups, as they involve random selection of comparison groups and are therefore less prone to selection bias. For M&V methods, the key criteria is that industry-standard protocols and guidelines are followed. These include the IPMVP, protocols published by the Federal Energy Management Program(FEMP), the American Society of Heating, Refrigeration and AirConditioning Engineers (ASHRAE), and the U.S. DOE’s UMP. (3) Key considerations for quantifying savings. Regardless of the approach used to quantify and verify MWh savings, EM&V plans must describe how they will address the following key considerations for quantifying savings:

 How major changes in independent variable conditions (weather, occupancy, production rates, etc.) that affect energy consumption and savings estimates will be analyzed. The effects of these changes can be calculated using either real-time conditions or normalized conditions that are reasonably expected to occur*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1007 of 1275 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 (e.g., most publicly or rate-payerfunded EE programs and project-based EE evaluated siteby-site and CHP, but not programs that provide customers with information). A key criterion is that verification 729 is required within the first year of program implementation. All verification activities must be performed using industry-standard techniques (e.g., phone or mail surveys, document review, site inspections, spot or shot-term metering). For projects implemented as part of a program, verification can be performed using a sample of projects to represent the full program population. In these cases, sample sizes should be defined per the rigor criteria described herein.

 How avoided T&D systems losses will be included in EE savings values. Demand-side EE programs (other than T&D efficiency measures such as CVR and volt/VAR

729 Verification is an independent assessment to ensure that the EE measures have been installed correctly and have the potential to generate the predicted savings. Verification may also include assessment of baseline conditions and confirmation that the EE measures are operating correctly per their design intent.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1008 of 1275 optimization 730 ) may adjust reported savings by using a T&D adder that is based on the lesser of 6 percent 731 of the site-level savings or the calculated statewide annual average T&D loss rate [estimated losses in MWh/(total electric supply – direct electricity use)] 732 expressed as a percentage and based on values in the most recent year and published US EIA State Electricity Profile. Since T&D efficiency measures such as CVR and volt/VAR may reduce both end-use consumption and line losses, MWh savings

from T&D measures must be calculated on the basis of procedures identified in an EM&V plan.

 How the duration of EE program or project electricity savings will be determined using annual verification assessments, industry-standard persistence studies, deemed estimates of effective useful life (EUL), or a

combination of all three. If deemed EUL estimates are used for determining the duration of savings, then zero

730 More information about these technologies is in section VIII.F.1 above. 731 6 percent is the national average losses from 1990-2012 (See: http://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3). 732 Estimated losses in MWh, total electric supply, and direct electricity use values are available in the U.S. EIA’s State Electricity Profiles. See table on Supply and Disposition of Electricity (currently Table 10). Direct electricity use refers to the electricity generated at facilities that is not put onto the electricity grid, and therefore does not contribute to T&D losses.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1009 of 1275 savings must be assumed at the end of a program, project, or measure life. If project or program persistence studies are conducted at least every 5 years to determine the duration of savings, then savings can be counted as long as the verification activities indicate continued measure operation and performance.

 How the rigor 733 of quantifying MWh savings values will be assessed, and the methods used to control the types of bias or error relevant inherent to the applied EM&V techniques. Rigor can be quantified using statistical indicators such as confidence and precision (for annual MWh savings, or for a representative sample of an EE program population), together with a written discussion of the EM&V approaches used, potential risks and biases, and related quality control measures that will be utilized. Sampling of populations is appropriate, provided that (a) the population estimates derived from sampling achieve industry-standard levels of precision and confidence (actual, not ex-ante values), and (b) applicable protocols and guidance documents are applied

733 Rigor refers to the level of effort expended to minimize uncertainty from factors such as sampling error and bias. The higher the level of rigor, the more confident one is that the results of the EM&V activities are both accurate and precise.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1010 of 1275

and cited.

 How double counting will be avoided through the use of tracking and accounting procedures to ensure that two or more programs do not separately claim savings from the same EE project or measure (for example, two EGUs claiming savings from the same lighting retrofit). Other types of double counting must likewise be considered and

avoided.(4) Use of EE EM&V protocols. A separate aspect of industrystandard EM&V practice addressed in the rule proposal is the use of one or more EM&V protocols, guidelines, and guidance. These resources serve to document the EM&V approaches listed above and provide instruction on their application in the field. In public comments, the EPA heard overwhelmingly that such protocols, guidelines, and guidance documents are currently in wide use, and that this use should be continued and encouraged in the context of state plans. The agency agrees with this observation and therefore supports their application in the context of demand-side EE used to adjust an emission rate. The primary criteria are that EM&V plans must include a clear description and documentation of how the relevant protocols, guidelines, and guidance documents will be applied, as well as after-the-fact documentation in EM&V reports of how they were actually applied.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1011 of 1275 c. Eligible demand-side EE programs and projects. During the comment period, the EPA received many requests from commenters for explicit consideration of the broad range of demand-side EE programs and projects that are currently being implemented by states and other entities across the country. Specifically, these commenters expressed interest in counting the resulting quantified and verified MWh savings towards the achievement of

CO 2 emission rate goals. Consistent with these perspectives, the EPA position is that any demand-side EE program and project that results in MWh savings is potentially eligible, provided that it meets the criteria for eligibility described in section VIII.G.1., and that supporting EM&V is rigorous, complete and consistent with the criteria provided in the emission guidelines and the state plan. Common demand-side EE programs and project types include:

 Publicly or rate-payer funded customer-funded demand-side management programs

 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1012 of 1275

standards A related technology that is eligible to generate MWh that can be counted towards a rate-based goal is CHP (more information about the eligibility and EM&V criteria for CHP is provided in section VIII.G.1.). The EPA 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 these programs can similarly be considered if quantified andverified according to EM&V criteria specified in industrystandard protocols and guidance documents, and if documentation provided in EM&V plans and reports is transparent, credible and

robust. d. Demand-side EE program- and project-specific EM&V provisions. In addition to the generally-applicable EM&V criteria specified above, EM&V plans and report submittals must include any additional EM&V information needed to ensure that savings from the previously-listed programs and projects are quantifiable and verifiable. This requirement can be fulfilled by documenting in EM&V plans how industry-standard protocols, guidelines, and guidance documents that are relevant to such programs and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1013 of 1275 projects will be applied on a forward-looking basis, and also by confirming in ex-post EM&V reports that they were, in fact, applied. The protocols, guidelines, and guidance documents that identify these provisions may currently exist, or may be developed during the course of the rule period as programmatic strategies and EM&V evolves. e. EM&V criteria that apply to non-affected CHP. To calculate a CHP unit’s creditable MWh, the electrical output is prorated

based on the “incremental CO 2 emission rate” of the CHP unit relative to the applicable CO 2 emission rate for affected EGUs in the state, according to the equation described in section VIII.C.1. The EM&V criteria described in this section apply only to the MWh-output terms of the equation, consistent with the definition of EM&V as applied in this rule. The full set of accounting criteria for CHP is provided in VIII.G.1. For determining the creditable MWh from CHP, the 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 CHP that is interconnected behind the customer meter, a revenue quality meter at the AC output of an inverter, where applicable, that is adjusted to reflect the energy delivered into either the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1014 of 1275 transmission or distribution grid at the generator bus bar. For small systems, defined as individual CHP units with nameplate capacities below 10 kW where metered data are unavailable, generation output may be determined using either self-reporting of generation values 734 or generation-estimating software. In the latter case, calculations of system output must be based on the CHP unit’s capacity, estimated capacity factors, and an assessment of the local conditions that affect generation levels. All such input parameters and assumptions must beclearly described and documented. Regardless of whether selfreporting or generation-estimating software is used, CHP providers can report results without an intermediary provided that EM&V plans describe the rigorous quality control and fraud prevention measures that will be applied. For small systems, generation output may be determined using either estimating software, algorithms, or self-reporting of generation values. In the latter case, EM&V plans must confirm that rigorous quality control and fraud prevention measures are in place. Small systems are defined as individual CHP units with nameplate capacities below 10 kW where metered

734 Self-reporting means that the generator-owner can read its own meter and report MWh generated directly to a tracking system, without relying on an independent third party or other representative.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1015 of 1275data are unavailable. For CHP systems that directly serve onsite end-use electricity loads, avoided T&D system losses can be assessed as is commonly practiced with demand-side EE. Such calculations must apply the criteria described in section VIII.G.4.(b)(3) above. f. EM&V criteria that apply to all RE. This section describes the EM&V criteria associated with quantifying electricity generation from eligible RE, and for documenting these criteria in EM&V plans and reports. Consistent with prevailing views expressed in public comments, the EPA’s criteria are based on the presumption that the quantification of RE generation can leverage the infrastructure and documentation associated with participation in registries of renewable energy certifications (RECs). These registries typically include well-established procedures for registry operations, safeguards, and documentation, all of which support compliance demonstration with state RPS policies. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1016 of 1275 customer meter, a revenue quality meter 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. 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. For RE units that do not go through a control area settlements process, metered data should be read and transmitted to the REC registry by an independent third party on a monthly basis, but at a minimum annually. Such data must be verified for reasonableness by the state or the REC registry. For small systems, defined as individual RE units with nameplate capacities below 10 kW where metered data are unavailable, generation output may be determined using either self-reporting of generation values or generation-estimating software. 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. In addition, each RE unit must*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1017 of 1275 be uniquely identified and recorded in a registry to avoid double counting. Such data must be verified for reasonablenessby the state or the REC registry. Regardless of whether selfreporting or generation-estimating software is used, RE providers can report the result to the tracking system without an intermediary provided that EM&V plans describe the rigorous quality control and fraud prevention measures that will be applied. An additional consideration is that RE generation may be aggregated from multiple generators into a single MWh value for the group, provided the following criteria are met: each RE unit is uniquely identified in a tracking system (to ensure that double counting is avoided), the nameplate capacity of each RE unit is less than 150 kW, the aggregated RE units collectively have nameplate generating capacities less than 1.0 MW, 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. An additional criterion that applies to distributed RE units that directly serve on-site end-use electricity loads is that avoided T&D system losses can be considered, as is commonly practiced with demand-side EE. Such calculations must apply the criteria specified for demand-side EE, as described in section*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1018 of 1275 VIII.G.4.(b)(3) above. g. Additional considerations for EM&V of RE and EE included in state measures type plans. As discussed in the introduction to this section, states implementing state measures type plans may use quantified and verified MWh of EE savings and RE generation to adjust an emission rate through two pathways. First, if the state measures plan enables rate-based trading, the affected EGUs may use ERCs to adjust their reported rate as applicable under the rate-based emission standard approach. In such cases, a state includes EM&V criteria (consistent with those discussed above) in its state plan requirements governing ERC issuance, trading and retirement. Second, if the state measures plan incorporates RE and demand-side EE policies, programs and projects outside of an ERC trading program – e.g., through adoption of an EERS or a RPS – the state itself, rather than the project provider, applies the quantified and verified MWh to adjust the reported emission rate used to demonstrate compliance with the emission guidelines. In the case of a state measures plan relying on stand-alone RE and EE measures, a state must submit as part of its state plan a description of the RE and EE measures it intends to implement, as well as a discussion of how it intends to quantify

the results of those measures consistent with the EMV criteria*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1019 of 1275 described herein. A key component of this discussion is the mechanisms and approaches the state intends apply to ensure that MWh savings and generation are independently and credibly quantified and verified. Such mechanisms and approaches must be consistent with industry-standard practices and functionally equivalent to the provisions for independent verifiers for ERC trading in the context of emission standard plans, as described section VIII.G.3. An additional and related component of the state plan is a forecast of expected RE generation and annual incremental and cumulative EE savings. For any state measures plan that incorporates demand-side EE and RE outside of an ERC trading program, an additional criterion is that states must report annual incremental and cumulative EE savings and RE generation to the EPA every year. 735 These data should be provided to the EPA in a summary format that documents total MWh savings and generation, and that is specified at the level of major policies, programs and projects. At state plan check-in intervals with the EPA (in 2025, 2028 and 2030), states must provide the EPA with access to applicable program- and project-level EM&V reports used to compile total MWh savings and generation. EM&V reports must

735 Per 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1020 of 1275 document how EM&V criteria were applied to quantify results. It should be noted that, in the case of state measures plans that utilize a mass-based allowance trading program to meet their goal, EM&V plans and reports are not required. This is true even if the state is actively implementing RE and demand-side EE programs and projects. This is because the

emission effects of RE and EE are accounted for in measured

stack emissions. h. Skill certification standards. Several commenters pointed out that skill certification standards can help to assure quality and credibility of demand-side EE and RE projects. The EPA agrees that in conjunction with other EM&V measures discussed in this section, requiring that workers be certified by either a party 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 a state apprenticeship program approved by the DOL, or by another skill certification validated by a third party accrediting body can help to substantiate the authenticity of emission reductions due to demand-side EE and RE. The EPA encourages states to ask for a demonstration that the work is performed by a proficient*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1021 of 1275

workforce.

H. Additional Considerations for State Plans 1. Consideration of a facility’s “remaining useful life” and

“other factors” This section discusses the way in which the final emission guidelines address the CAA section 111(d)(1) provision requiring the Administrator, in promulgating 111(d) regulations, to “permit the State in applying a standard of performance to any particular source under a [111(d)] plan . . . to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.” 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, asdiscussed further below. Therefore, consideration of facilityspecific 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1022 of 1275 consider these factors in designing their plans. a. Statutory and regulatory backdrop. 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 736 addressed a number of facility-specific factors that might affect requirements for an existing source under section 111(d). Those regulations provide that for designated pollutants, standards of performance in state plans must be as stringent as the EPA’s emission guidelines. Deviation from the standard might be

736 40 FR 53340 (Nov. 17, 1975).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1023 of 1275 appropriate where the state demonstrates with respect to a specific facility (or class of facilities): (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 “Unlessotherwise specified in the applicable subpart on a case-bycase basis for particular designated facilities or classes of facilities.” 40 CFR 60.24(f). b. Our proposal regarding the implementing regulations. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1024 of 1275 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 noted, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1025 of 1275 which such standard applies.” c. How these emission guidelines permit states to consider remaining useful life and other facility-specific factors. 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, and Kraft pulp plants specify emission limits for sources. 737 In the case of such emission guidelines, some individual sources, by virtue of their age or other unique circumstances, may warrant special

accommodation.

737 See “Phosphate Fertilizer Plants; Final Guideline Document Availability,” 42 Fed. Reg. 12022 (Mar. 1, 1977); “Standards of Performance for New Stationary Sources; Emission Guideline for Sulfuric Acid Mist,” 42 Fed. Reg. 55796 (Oct. 18, 1977); “Kraft Pulp Mills, Notice of Availability of Final Guideline Document,” 44 Fed. Reg. 29828 (May 22, 1979); “Primary Aluminum Plants; Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 (Apr. 17, 1980); “Standards of Performance for New Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 (Mar. 12, 1996).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1026 of 1275 In these final guidelines for state plans to limit CO 2 from affected EGUs, however, the agency does not specify presumptive performance rates for individual EGUs. Instead, these guidelines provide collective performance rates for two classes of affected EGUs (steam generating units and stationary combustion turbines), and give states the alternative of developing plans to achieve a state emission goal for the collective group of all affected EGUs in a state. Providing states with the ability to consider facility-specific factors such as remaining useful life in designing their state plans is one of the fundamental reasons that the EPA designed the final rule in this way. In addition, the significant revisions since proposal to address achievability concerns (e.g., moving the start date from 2020 to 2022, and other changes in interim and final state goals summarized in the next section) will help to ensure that states in practice can consider remaining useful life and other facility-specific factors in setting EGU requirements. Of course, EGUs vary considerably in age, so remaining useful life is potentially relevant to regulation of some units and not

others. The guidelines capitalize on the inherent flexibility offered by aggregate EGU performance rates and by the state goals approach, allowing states flexibility on the form of the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1027 of 1275 EGU standards that they include in CAA section 111(d) plans. A state could select a form of standards (e.g., marketable credits or permits, retirement of certain older facilities after their useful life, etc.) that avoids or diminishes concerns about facility-specific factors such as remaining useful life. Even if a state adopted the CO 2 emission performance rates for fossil fuel-fired electric utility steam generating units and stationary combustion turbines, though, the state could take remaining useful life into consideration by allowing affected EGUs to comply using ERCs. 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 ERCsthan the second facility. Buying ERCs could avoid excessive upfront capital expenditures that might be unreasonable for a facility with a short remaining useful life, and would reduce the potential for stranded assets. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1028 of 1275

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 2 emission goal, and that each of these pathways allow states multiple design choices. Under either pathway states can take into consideration remaining useful life and

seek to avoid stranded assets. d. Why remaining useful life and other facility-specific factors do not warrant adjustments in the guidelines’ performance rates and state goals. Under the final guidelines, remaining useful life and other facility-specific considerations do not provide a basis for adjusting the CO 2 emission performance rates, or the

state’s rate-based or mass-based CO 2 emission goals, nor do they affect the state’s obligation to develop and submit an approvable CAA section 111(d) plan that adopts the CO 2 emission performance rates or achieves the goal by the applicable deadline. After considering public comments discussed below and in the response to comments document, the EPA has retained this*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1029 of 1275 aspect of the proposed rule for the reasons described below. As noted above, the final guidelines provide aggregate emission goals for affected EGUs in each state, in addition to

the CO 2 emission performance rates. The guidelines also reflect a number of changes from proposal to address concerns about achievability of proposed state goals that were raised in public comments, many of which were explicitly prompted by consideration of the remaining useful life issue. The result is to afford states with broad flexibility to design requirements

for affected EGUs to achieve the CO 2 emission performance rates

or state CO 2 emission goals in ways that avoid requiring major capital expenditures, or imposing unreasonable costs, on those affected EGUs that have a limited remaining useful life. State plans may use any combination of the emissions reduction methods represented by the building blocks, and may also choose to employ emission reduction methods that were not assumed in calculating state goals. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1030 of 1275 implementation levels for each building block in order to establish overall 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 goal 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 section VIII.G. f. Response to key comments on remaining useful life. In response to the proposed rule, some commenters said that stringent and binding state goals do not, as a practical matter, provide states with the flexibility on EGU requirements that the EPA claimed at proposal, and take away states’ ability to consider remaining useful life for individual units. Some said the EPA’s presumption at proposal that the issue of remaining useful life would arise infrequently is inaccurate because the EPA focused on capital investments late in a plant’s useful life

and did not consider stranded assets from retirement of coalfired generation before the end of its useful life, or from retirement of EGUs that recently installed pollution controls. Commenters provided multiple examples of individual power plants, including relatively new plants, which they asserted*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1031 of 1275 would be forced to shut down under the proposal. One commenter said that the EPA’s Integrated Planning Model outputs for the proposal demonstrate that integrated operation of the four building blocks would result in retirement of sources before the

end of their useful life. A number of commenters raised concerns that the proposed interim goal would cause plant retirements and

stranded assets. A number of commenters also asserted that the proposal would cause retirement of EGUs that recently invested in pollution controls to comply with requirements such as MATS or Best Available Retrofit Technology requirements of the Regional Haze program. The EPA shares the goal of avoiding stranded assets. Although nothing in section 111(d) explicitly bars a guideline that results in some facilities becoming uneconomic before the end of their useful lives, the EPA nonetheless has striven to design the guidelines so as to give states flexibility to develop plans that allow power companies to recover their investments in generation units. In addition, the EPA is addressing the key comments above by making changes to state goals and its goal-setting methodology. These changes include:

 Starting the interim goal period in 2022 rather than 2020, allowing more gradual progress toward the final*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1032 of 1275 goal

 Revising the goal-setting formula and the state goals

themselves

 Updating analyses of achievable levels of improvement through the building blocks that together represent the BSER, while keeping them at reasonable, rather than maximum, levels

 Providing an explicit phase-in schedule for meeting the revised interim goals, while also allowing a state the option of choosing its own emission improvement trajectory The final guidelines also contain changes to avoid certain inconsistencies between the goal-setting methodology and accounting of reductions under state plans (e.g., interstate effects of RE programs) that could have made state goals less

achievable for some states. Together, these changes help to ensure that the state goals established in the final guidelines are achievable considering cost, and that states can, as a practical matter, consider the

toolbox of available emission reduction methods that the final guidelines allow and choose the best way to achieve their state goals.

Several commenters said that that the statute does not*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1033 of 1275 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, many of which appear to be predicated on an approach not taken in this rule: requiring states to set presumptive standards for individual affected EGUs. The EPA is not establishing BSER for individual facilities, and then requiring better-than-BSER from some facilities to make up to worse-than-BSER performance that a

state authorizes for other facilities because of a short remaining useful life. Rather, as previously noted, the guidelines set aggregate performance rates and state goals that represent the aggregate emission level of affected EGUs in each state based on estimates of the aggregate impact of applying the BSER. In estimating the amount of improvement achievable through each building block e.g., improvement in heat rate or amount of generation shift to lower-emitting EGUs), the EPA relies on*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1034 of 1275 estimating the average achievable level rather than attempting to estimate the level achievable by each and every affected EGU. Thus, the fact that an individual facility may be unable, for example, to achieve the average level of heat rate improvement assumed in goal-setting is consistent with the EPA’s analysis, and does not undermine the EPA’s determination of state goals.

An additional reason that the EPA believes thatconsideration of remaining useful life and other facilityspecific 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. Of the building blocks considered by the EPA in developing state goals, only the first block, heat rate improvements, involves capital investments at the affected EGUs. The other building blocks – 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. In the case of heat rate improvements at affected EGUs, states can choose whether to require a greater or lesser degree of heat rate improvement than the percentage improvement assumed in the EPA’s BSER determination, either because of the remaining useful life of one or more EGUs, other source-specific factors*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1035 of 1275 that the state deemed appropriate to consider, or any other relevant reasons. The agency also notes that any capital expenditures would be much smaller than capital expenditures required for example, for purchase and installation of scrubbers to remove sulfur dioxide; a fleet-wide average cost for heatrate improvements based primarily on best practices at coalfired generating units would not likely exceed $100/kW, compared with a typical SO 2 wet scrubber cost of $500/kw (costs vary with unit size). 738 In addition, the proposed guidelines allow states to regulate affected EGUs through flexible regulatory approaches that do not require affected EGUs to incur large capital costs (e.g., averaging and trading programs). Under the EPA’s proposed approach - establishing state goals and providing states with flexibility in plan design – states have flexibility to make exactly the kind of judgments necessary to avoid requiring capital investments that would result in stranded assets. 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

738 Heat rate improvement methods and related capital costs are discussed in the GHG Abatement Measures TSD; SO 2 scrubber capital costs are from the documentation for the EPA’s IPM Base Case v5.13, Chapter 5, Table 5-3, available at http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1036 of 1275 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 2 emission performance rates or state CO 2 emission goals on time. The EPA therefore concludes that the remaining useful life of affected EGUs, and the other facility-specific factors identified in the existing implementing regulations, should not be regarded as a basis for adjusting the CO 2 emission performance

rates or a state CO 2 emission goal, and should not relieve a state of its obligation to develop and submit an approvable plan that achieves that goal on time. g. Legal issues regarding remaining useful life. Section 111(d)(1) requires the EPA in promulgating section 111(d) regulations to “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.” Here, we discuss the legal basis for determining that the emission guidelines are consistent with this statutory requirement. First, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1037 of 1275 EPA) must take into consideration (among other factors) “the remaining useful life of the source.” 42 USC 7491(g)(2); see

also id. (g)(1) (reasonable progress). 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. See 40 CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost is then used to determine a cost effectiveness, in dollars per ton of pollutant removed on an annual basis. As a result, a technology with a large initial capital cost that might have a reasonable cost-effectiveness for a facility with a long remaining usefullife would have a much higher and possibly unreasonable costeffectiveness for a facility with a short remaining useful life. However, section 111(d)(1) is different than section 169A(g)(2) and need not be interpreted in the same way. The requirement in section 169A(g)(2) is a mandatory duty to consider remaining useful life in determining BART. Section 111(d)(1), in contrast, merely requires that EPA emission guidelines permit states to take into account remaining useful life (among other factors), and section 111(d)(1) does not specify how the EPA must permit that. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1038 of 1275 imagined. Thus, there is a gap in the statute (just as there is in section 169A(g)(2)) for the EPA to fill by determining how states might consider remaining useful life. As detailed in section VIII.B.6, 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. Even if the EPA were to consider the provision in section 111(d)(1) in the same light as section 169A(g)(2), we would note (as discussed in detail in VIII.B.6 above) that (for example) a trading program under these section 111(d) guidelines only requires compliance on a periodic basis and does not require any initial capital expenditures. Thus, over the life of the facility, 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 other words, under a trading program remaining useful life of a source is automatically accounted for in the way it is accounted for under the visibility program. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1039 of 1275 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.B.6 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 state performance goal. In fact, that sentence is completely silent on the issue. Thus, there is a gap in the statute to fill not only with respect to the ways in which remaining useful life can be considered, but the concomitant*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1040 of 1275 effects if a state chooses to consider remaining useful life in a particular way. In this case the concomitant effect of a state relaxing one emission standard may be that the state must make up for it elsewhere in order to meet the goal, but nothing in section 111(d)(1), including the statutory requirement to permit consideration of remaining useful life, prohibits that outcome. 2. Electric reliability The final rule features overall flexibility, a long planning and implementation horizon, and the widest possible range of options for states and affected EGUs to achieve the CO 2 emissions goal. This design reflects, among other things, the EPA’s commitment to ensuring that the final rule does not interfere with the reliability of the nation’s electricity supply. Comments from state, regional and federal reliability entities, power companies and others, as well as consultation with the Federal Energy Regulatory Commission (FERC), which conducted one national and three regional technical conferences on the proposed rule in which the EPA participated, helped inform a number of changes made in this final rule to address reliability. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1041 of 1275 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 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1042 of 1275 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. 739 Long-term system planning happens at both the local and regional levels with all segments of the electric system needing to operate together in an efficient and reliable manner. In the short-term, electric system operators operate the system within safe operating margins and work to restore the system quickly if a disruption occurs. 740 Mandatory reliability standards apply to how the bulk electric system is planned and operated. For

739 Casazza, J. and Delea, F., Understanding Electric Power Systems: An Overview of the Technology, the Marketplace, and Government Regulations , IEEE Press, at 160 (2010). 740 Id.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1043 of 1275 example, transmission operators and balancing authorities have to develop, maintain, and implement a set of plans to mitigate operating emergencies. 741 The EPA’s approach in this final rule is consistent with our commitment to ensuring that the final rule does not interfere with the reliability of the nation’s electricity supply. Starting with the proposal, many aspects of the final rule’s design were intended to support system reliability, especially the long compliance period and the basic design that allows states 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 energy resources and policies. Indeed, 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. Changes that the EPA is making in this final rule respond directly to the comments and the suggestions we received on these issues and provide further

741 NERC Reliability Standard EOP-001-2.1b — Emergency Operations Planning, available at http://www.nerc.net/standardsreports/standardssummary.aspx.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1044 of 1275 assurance that implementation of the final rule will not create reliability concerns. First, the final rule allows significant flexibility in how the applicable CO 2 emission performance rates or the statewide

CO 2 goals are met. Given the differing characteristics of the electric grid within each state and region, there are many paths to meeting the final rule’s requirements that can be taken while continuing to maintain a reliable electricity supply. As further described elsewhere in Section VIII, states can develop plans to

meet the CO 2 emission performance rates or state CO 2 emission goals by choosing from a variety of state plan types and approaches that afford states and affected EGUs appropriate flexibility. EE and other non-BSER approaches can strengthen a state’s ability to establish a plan to meet the CO 2 emission performance rates or state CO 2 emission goals by providing a

considerable amount of headroom above the levels of the rates and goals. EE especially, because it reduces load, can provide assurance that reliability can and will be maintained. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1045 of 1275 concern by both moving the start of the interim period from 2020 to 2022 and adjusting the interim goals to provide a less dramatic initial reduction requirement and a more gradual glide path to the final 2030 goals. As a result of these changes, the states themselves will have a meaningful opportunity – which 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 six years before reductions are required and an eight-year period from 2022 to 2029 to meet interim goals. Third, we are including in the final rule a requirement that each state demonstrate in its state plan submittal that it has considered reliability issues in developing its plan. This was suggested by a number of commenters, and we agree it is an

essential element. Fourth, 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 inform the EPA that an affected EGU or EGUs may need to temporarily deviate*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1046 of 1275 from specific state plan requirements to respond to this kind of reliability concern. Finally, 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. 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. Summary of key comments. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1047 of 1275 and system changes that need to be made to comply with final rule requirements while allowing affected EGUs time to meet

interim CO 2 emissions goals. The EPA also received comment that market-based approaches have features that could help support reliability, and therefore we should encourage states to join or form regional market-based programs. Commenters also stated that the EPA should require states to consult with grid operators who would analyze the impact of state plans on reliability. A number of commenters also suggested that the EPA should include some sort of reliability safety valve in the final rule. We note that many participants at the FERC technical conferences on the proposed rule also discussed a reliability safety valve in great detail with many suggestions for how such a reliability mechanism could be designed. The EPA appreciates these and all the comments we received regarding the interaction of the proposal and electric reliability. We carefully considered all comments and incorporated many of the suggested changes in this

final rule. b. Final rule flexibility. 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 steer clear of potential reliability disruptions, a number of commenters argued that the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1048 of 1275 possibility of an unanticipated reliability event cannot be entirely eliminated. Of course, even in the absence of these guidelines, the electric system will not completely avoid reliability issues. 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. However many commenters expressed concern that notwithstanding these flexibilities, 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. The final rule also provides the states with up to three years to adopt and submit their final state plans. This timing gives system operators the opportunity to do what they have already been doing; looking ahead to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1049 of 1275 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. 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. Considering reliability during state plan development process. 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 is requiring that each state demonstrate as part of its state plan submission that it has considered reliability issues while developing its plan in order to ensure that standards of performance can be implemented and enforced. If system reliability is threatened, the ability of affected EGUs to meet the requirements of this final rule could be compromised if they are required to operate beyond the emission standards set in state plans in order to maintain the reliability of the electric grid. The requirement that states*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1050 of 1275 consider reliability as part of the development of state plans is designed to ensure that state plans are flexible enough to avoid this kind of potential conflict between maintaining reliability and implementing emission standards for affected

EGUs. A number of commenters, notably ISOs and RTOs, 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 a state 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 state should request that the planning authority review the state plan at least once during the plan*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1051 of 1275 development stage and provide its assessment of any reliability implications of the 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 state plan submittal to the EPA. This consultation is designed to inform how the state might adjust its plan for meeting the CO 2 reduction goal required under this guideline; the consultation is not a basis for relaxing that goal. While we consider this process to be an effective way for a state to demonstrate that it considered reliability in developing its state plan, a state may provide other comparable support for a demonstration that it has considered reliability during the state plan development

process. 742 The EPA believes that this requirement to demonstrate consideration of reliability will provide an essential reliability evaluation in the state plan development process. It should further help states avoid any conflicts between state plans and the maintenance of reliability during implementation of the state plan and associated emission standards.

742 While the EPA is requiring that the states demonstrate that they have considered reliability in developing their plans, state plan submissions will not be evaluated substantively regarding reliability impacts.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1052 of 1275 d. State plan modifications. 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 the timeframe over which reductions must be made in 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. Whether or not these circumstances occur will depend in part upon how each state designs its state plan. States that design plans with a good deal 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 risks to reliability. Events not anticipated at the time of the final plansubmittal - such as the retirement of a large low or zeroemitting unit - may trigger the request for state plan revisions. It may also be the case that facility-specific emissions 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1053 of 1275 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 requirements of 40 CFR part 60. If the state’s request for a state plan revision must be addressed promptly 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. Reliability safety valve. Many commenters expressed concerns that a serious, unforeseen event could occur during the final rule implementation period that would require a quick response by system operators and affected EGUs in order to maintain system reliability. 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 plants. While some have pointed out*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1054 of 1275 severe weather or other short-term events as potentially conflicting with state plans, we note that most of those events are of short duration and would not require major adjustments to emission standards on affected EGUs or 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 briefly runat a higher level to accommodate increased demand and/or shortterm unavailability of other generators. However, because compliance can be demonstrated over 2-3 years, such a short-term event would not cause affected EGUs to be out of compliance with their applicable requirements. States can ensure that this is true by drafting plans that allow adequate compliance flexibility to accommodate such short-term events. We recognize, however, 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. There could be extremely serious events, outside the control of affected EGUs, that occur that require an affected EGU, or EGUs, to temporarily deviate from specific state plan requirements to respond to this kind of reliability concern. For example, 1) a catastrophic event such*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1055 of 1275 as a geomagnetic disturbance caused by solar flares damages critical or vulnerable equipment necessary for reliable grid operation and a higher emitting resource needs to operate at increased levels until an alternative solution can be found; or 2) a major storm floods and causes severe damage to a large NGCC plant in a city with limited access to transmission, necessitating that another much higher emitting plant is needed to operate until the NGCC plant is repaired; or 3) a serious act of sabotage damages an important substation and it will take time to work around the problem, and in the meantime a high emitting plant will need to run until transmission access is restored; or 4) a large nuclear unit must cease generating due to a substantial public safety issue and therefore causes other affected EGUs to run at higher levels in the short-term until a longer-term solution can be found. This is not an all-inclusive list, but it is illustrative of the kind of unforeseeable, emergency situation, caused by an extraordinary, unanticipated, potentially catastrophic event that, in the case of a state plan that imposes inflexible, obligations on individual EGUs (especially with short averaging times), may trigger the need for immediate, short-term relief from those facility-specific requirements. In such an instance, the final rule provides a process to ensure that system reliability will not be*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1056 of 1275 compromised. Under such a circumstance, for states using the emissions standards plan type, the state must notify the EPA that it is necessary to modify the emission standards for an affected EGU or EGUs so that for a maximum of 90 days, the EGU or EGUs may operate at an emission standard that is above the emission standard specified in the relevant state plan but that the CO 2 emission performance rates or the state CO 2 emission goal will still be met. The EPA will consider this reliability safety valve 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 proper notification to the EPA. The notification to the EPA must be in writing and must include a full description of the reliability concern and why the affected EGU (or EGUs) needs to operate under modified emission standards from those originally imposed on it by the state plan.

The state must also describe in its notification to the EPA how it is coordinating or will coordinate, with relevant planning authorities to alleviate the problem in an expedited manner. The

state should also include a written concurrence from the relevant planning authority supporting the temporary modification request or an explanation of why this kind of concurrence cannot be provided. Additionally, if the relevant*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1057 of 1275 planning authority has conducted a system-wide or other analysis of the reliability concern, the state should include that information in its request. It is important to note that in such an instance requiring a short-term modification to the state plan, the state and affected EGUS must continue monitoring and reporting their emissions and generation pursuant to requirements in this final rule and under the state plan. Additionally, a short-term modification to the state plan is specific to the emissions standards for the affected EGU(s) needing to operate in a way that ensures system reliability, but such a modification may not alter or abrogate the overall obligations under approved state plans for the requisite state goal or performance rates to be met by affected EGUs. At the end of this period of 90 days or less, the state must notify the EPA as to whether the reliability concern has been addressed and that it is requiring the affected EGU, or EGUs, to meet the original emissions standards in the state plan approved prior to the short-term modification going forward. It must also notify the EPA as to how the CO 2 emission performance

rates or state CO 2 emission goals will be met going forward and enumerate how it will make up for any emission reductions that were lost during the safety valve period. If there still is a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1058 of 1275 serious, ongoing reliability issue, the state must provide to the EPA a notice that it will be submitting a state plan revision. At the end of this period of 90 days or less, the emission standards originally approved under the state plan must

be back in effect for the affected EGUs. The EPA intends for this reliability safety valve to be used only in exceptional cases and only once by a state. As discussed earlier, we are providing states with the flexibility to design a program that is appropriate for its electricity needs. This flexibility means that a conflict between the requirements of the state plan and maintenance of reliability should be extremely rare. If, however, the state finds that problems remain after imposition of the reliability safety valve, the state must submit a revision to its state plan.

3. Consideration of effects to employment and economic development Labor markets respond in complex ways to state policies in a way that depends a wide range of factors (e.g., available local labor supply, broader labor market trends). Employment effects in a state will depend upon the particular steps that each state takes in their plan, as well as broader trends at the regional and national level. For most state plans, the precise effects will often be very hard to quantify because they will*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1059 of 1275 depend on choices made by utilities and others as the plans are implemented. The EPA’s illustrative analysis highlights the

likelihood for some additional job loss in sectors related to coal that are attributable to implementation of this rule. At the same time, the EPA’s illustrative analysis highlights that there will be new jobs in the utility power sector associated with both improving the efficiency of fossil fuel-fired power plants and construction of new natural gas-fired and renewable power production, and new jobs in the RE and demand-side EE

sectors. 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 and economic goals. The Partnership 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 that specially targets economic development assistance to communities affected by changes in the coal industry and the utility power sector and may be of assistance to communities that experience job losses. 743 In addition, the Department of Commerce, Department of Labor (DOL), Small Business Administration, and the Appalachian Regional Commission

743 http://www.eda.gov/power/.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1060 of 1275 have together created an initiative to issue grants to partnerships of regionally-driven economic development and workforce development organizations in impacted coal

communities. 744

4. Workforce considerations 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. The EPA agrees and encourages states to ask for a demonstration that the work 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. 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. 5. Tenth Amendment legal considerations

744 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1061 of 1275

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 “commandeer” that state into submitting its own satisfactory plan. Far from violating principles of federalism, this rule provides states with the initial opportunity to submit a satisfactory state plan, and provides states flexibility in developing that plan. If a state declines to take advantage of that opportunity, affected EGUs in that state will instead be subject to a federal plan that satisfies statutory requirements. 745 This approach is consistent with ordinary

745 Among other things, a federal plan will implement standards of performance subject to specific statutory requirements. See 42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the imposition of any federal plan that is “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 5 U.S.C. § 706(2)(a). Particularly given these independent constraints on the EPA’s authority with respect to any potential*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1062 of 1275 cooperative federalism regimes that federal courts have routinely upheld against Tenth Amendment challenges. 746 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 the implementing regulations 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. 747 Section 110(m) grants the EPA discretionary authority to withhold some federal highway funds under certain conditions. However, section 110(m) requires the EPA to adopt regulations to “establish criteria for

federal plan, the prospect of any such plan would not commandeer states or coerce them into submitting their own state plans. 746 See, e.g. , Hodel v. Va. Surface Mining & Reclamation Ass’n, Inc. , 452 U.S. 264, 283–93 (1981); Texas v. EPA , 726 F.3d 180, 196–97 (D.C. Cir. 2013) (noting that “Supreme Court precedent repeatedly affirm[s] the constitutionality of federal statutes that allow States to administer federal programs but provide for direct federal administration if a State chooses not to administer it”). 747 Other commenters point to CAA section 179 as a possible direct source of this sanctions authority. However, the mandatory sanctions outlined in section 179 clearly apply only in the context of nonattainment SIPs. See 42 U.S.C. § 7509(a).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1063 of 1275 exercising” this discretionary authority, and the only EPA regulations implementing section 110(m) apply to SIPs submitted

under section 110. 748 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 rule today 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. I. Resources for States to Consider in Developing Plans 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

748 40 CFR 52.30 (defining “plan or plan item”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1064 of 1275 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 requestedclear guidance on how to measure the impacts of RE and demandside 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1065 of 1275 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: http://www2.epa.gov/ www2.epa.gov/cleanpowerplantoolbox. The site includes information on regulatory requirements, including state plan guidance and state plan decision support. The state plan guidance section serves as a central repository for the final emission guidelines, RIA, guidance documents, TSDs and other supporting materials. The state plan decision support section includes information to help states evaluate different approaches and measures they might consider as they initiate plan development. This section includes, for example, a summary of existing state climate and RE and demand-side EE policies and programs, information on electric utility actions that reduce

CO 2 , and tools and information to estimate the emissions impact of RE and demand-side EE programs.

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 website does not necessarily imply the approvability of an approach or*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1066 of 1275 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. **IX. Community Considerations** Climate change is an environmental justice issue. Certain people and communities are more vulnerable to the health and economic impacts of climate change than others, including low income communities, communities of color, and indigenous

communities. Limited resources make some communities less able to either adapt to anticipated changes or recover from the impacts. Existing health disparities, including an already high burden of chronic health conditions, and other inequities in these communities contribute to their increased vulnerability. Climate change impacts add to the cumulative stresses currently faced by these populations. 749 The purpose of this rulemaking is to substantially reduce

emissions of CO 2 from fossil-fired power plants in the United States. These emissions contribute to climate change, which has been documented to cause adverse health and economic impacts to

749 USGCRP 2014: Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1067 of 1275 communities in the United States, as well as globally (a more robust discussion of how the agency satisfied Executive Order 12898 can be found in section XII.J of this preamble). This rule is one significant step that, along with other domestic programs (such as the tailpipe standards and fuel efficiency requirements for light, medium, and heavy duty motor vehicles) and programs that other countries are putting in place, will begin to address the global phenomenon of climate change. The EPA has received extensive input and has had numerous discussions with community members and representatives of environmental justice advocacy organizations throughout this rulemaking. We have heard that this rule is vitally important to

residents of vulnerable and overburdened communities as it directly addresses climate change, which is an issue of concern for communities. Additionally, we have heard concerns that the plans that states will develop to implement the emission guidelines must be sensitive to and protect against the possibility of disproportionate impact on those communities that live near power plants. We received feedback that it is critical that states provide meaningful opportunities for public participation in the development of their plans and that they pay attention to how their plans may affect overburdened communities. We have also heard concerns about potential co-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1068 of 1275 pollutant increases in communities due to operational and efficiency changes as a result of some affected EGUs potentially being dispatched more intensively in the future than they were in the past. We have also heard concerns about the potential for this rulemaking to have disproportionate high and adverse human

health or environmental effects on affected communities. Stakeholders have also strongly conveyed to us that low income communities represent tremendous opportunities for deployment of energy efficiency (EE) and renewable energy (RE) compliance options, but that focused strategies are essential to ensure robust adoption of these technologies by low income communities. As the scientific literature presented in section II.A of this preamble and the Executive Order 12898 discussion in section XII.J of this preamble outline, low-income communities and some communities of color are especially vulnerable to the health and other adverse impacts of climate change. The EPA believes that all communities, including low-income communities and communities of color, will benefit from this final rule because this action directly addresses the impacts of climate change by limiting GHG emissions through the establishment of CO 2 emission guidelines for existing affected fossil fuel-fired EGUs and provides significant co-benefit reductions in conventional air pollutants.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1069 of 1275

This rule can affect vulnerable communities in several ways. First, this rule will reduce the adverse impacts of climate change that can affect vulnerable communities disproportionally. These are impacts at global and national

scales and reductions of CO 2 anywhere will benefit communities everywhere. To the extent that this rule is an important step in the global effort to address climate change, vulnerable communities are important beneficiaries. The second way this rule can affect communities is through

the co-benefit reductions in criteria and hazardous air pollutants (PM, NOx, and mercury, for example) that will occur as a result of a shift to a cleaner and more efficient power sector. Our analysis shows projected reductions of XXX,XXX tons in 2030 across the country. Impacts from emissions of these pollutants are at local and regional scales, and these reductions will lead to improved public health both in the communities where the facilities reducing emissions are located as well as many miles downwind of those facilities. Therefore, low income communities, communities of color, and indigenous communities are already more vulnerable to the adverse public health impacts of climate change and therefore will especially benefit from the reductions in air pollutants as a result of

this rule.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1070 of 1275 Other impacts that may be anticipated from this rule can affect communities in various ways. The electricity sector is, and will continue to be, investing more in renewable energy (RE) and in energy efficiency (EE). These trends may impact affected communities in at least two ways. First, the expansion of RE and EE both provide opportunities for job creation and investment in communities. Second, shifts in how electricity is produced and used may lead to changes in the cost of electricity and consequent electricity bills. A significant barrier to the adoption of EE and RE by affected communities is the higher upfront cost (e.g., of purchasing a more efficient appliance or installing rooftop solar panels). It is important that communities impacted by state plans are able to access EE and RE so that they can take advantage of these opportunities to lower their electricity bills. The EPA believes it is important for states to consider these potential impacts on affected communities as they are developing their plans. Environmental justice stakeholders are nonetheless concerned about possible local increases in pollution that may arise from increased dispatch of certain units. In the remainder of this section of the preamble, we address these many issues and the results of an analysis we conducted to assess the proximity of vulnerable communities to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1071 of 1275 fossil fuel- fired power plants in the United States. Additionally, we discuss one of the most important ways to minimize potential adverse impacts — of whatever kind

− on vulnerable communities: a robust public engagement process for state plan development that provides meaningful opportunities for participation, evaluation of potential impacts, and a discussion of ways to address then. Furthermore, we explain changes we have made to the rule to address these issues. These final emission guidelines will be implemented by each state upon the EPA’s approval of a state plan. The EPA has included a number of conditions to help ensure that affected communities will be able to participate meaningfully in the development of state plans and that this action will not have potential disproportionately high and adverse human health or environmental effects on communities, including low-income

communities and communities of color. The conditions outlined in this section of the preamble were considered as part of the EPA’s analysis under Executive Order 12898.

A. Proximity Analysis To further ensure that this rulemaking does not have any potential disproportionately high and adverse human health or environmental effects on vulnerable communities, the EPA has conducted an analysis for this final rulemaking that summarizes*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1072 of 1275 demographic data on the communities located near power plants (a proximity analysis). The EPA understands that, in order to prevent any potential disproportionately high and adverse human health or environmental effects on these communities, both

states and communities must have information on the communities living near facilities, including demographic data, and that accessing and using census data files requires expertise that some community groups may lack. Therefore, the EPA used census data from the American Community Survey (ACS) 2008-2012 to conduct a proximity analysis for this rulemaking, and the analysis and its results are presented in the EJ Screening Report for the Clean Power Plan, which is located in the docket for this rulemaking. 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. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1073 of 1275 urban power plants. There are many rural power plants that are located near small communities with relatively few persons of color but high percentages of low-income populations. In urban areas, nearby communities tend to be both low-income communities

and communities of color.

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 CO 2 emission guidelines for existing affected fossil fuel-fired power plants. The EPA also believes that the information provided in the proximity analysis will promote engagement between affected

communities and their states and will be useful for states as they begin developing their plans. Furthermore, the EPA has also created an interactive mapping tool that illustrates where power plants are located and provides information on a state level.

This tool is available at: http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/.

B. Title VI 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1074 of 1275 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 implementation plans of the Clean Power Plant guidance 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 EPA’s OCR.

C. Community Engagement in State Plan Development*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1075 of 1275 Additionally, meaningful public involvement as described in EPA’s 2006 Public Involvement Guidance (71 Fed. Reg. 14,207) should play a pivotal role to ensure that the state implementation plans of the Clean Power Plant guidance do not violate any of the federal nondiscrimination statutes. States should seek opportunities to enhance public involvement in the environmental decision-making process, including providing access to limited English proficient individuals, as a means of hearing and considering communities’ concerns early in the process which may potentially reduce the chances of a Title VI complaint being filed about a recipient’s actions. As highlighted above the EPA is requiring that states engage with all stakeholders throughout the state plan development process and that states consider and address all feedback received as they create their final plans. In section VIII.D of this preamble, the EPA notes that states need to ensure that there is meaningful involvement for all members of the public during the initial and final plan submittal process. This engagement includes providing the opportunity for public comment on the state’s draft submittal and responding to significant comments received (including comments from communities potentially impacted by their plan), as well as conducting a public hearing before a final state plan is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1076 of 1275 submitted. 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 EPA will require that states demonstrate that they are actively engaging affected communities as part of their public participation process. The steps that states could take to demonstrate that they are actively engaging the public, including communities affected by their plan, are outlined in section VIII.E of this preamble. Additionally, as outlined in section VIII.D of this preamble, the final plan submitted by states should include an overview of the public hearing(s) conducted and information on how the state ensured that the hearing(s) were accessible to communities that may be potentially impacted by their plan. It is important to the EPA that affected communities have the information needed to effectively engage with states during the state plan development process. At the same time, it is important to the EPA that states also have support in engaging with affected communities throughout the state plan development process. As a result, the EPA will provide training and other resources throughout the implementation process that will assist affected communities and states as they engage with one another. These trainings will be a continuation of those that the EPA has already conducted with communities and states both pre- and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1077 of 1275 post-proposal. The EPA will be reaching out to a wide variety of community stakeholders, including groups representing low-income communities and communities of color, faith-based organizations, academic organizations working with communities, and other community stakeholders. As noted in section VIII.C of this preamble, the EPA will encourage multi-state partnerships. Multi-state partnerships, like the Regional Greenhouse Gas Initiative (RGGI), have demonstrated their ability to invest in EE/RE programs and direct energy bill assistance programs in communities. 750 For example, from 2008-2013, RGGI invested over $1 billion in auction proceeds towards various policy priorities. 751 Investment into energy efficiency programs made up 62% of cumulative RGGI investments through 2013. 752 These investments are projected to earn an expected return of more than $2.3 billion in lifetime energy bill savings for 1.2 million households and 17,550

businesses. 753 Additionally, investments in clean and renewable energy make up 8% of cumulative investments and these investments are expected to yield a return of more than $240

750 Investment of RGGI Proceeds through 2013.http://www.rggi.org/docs/ProceedsReport/Investment-RGGIProceeds-Through-2013.pdf 751 Ibid. 752 Ibid. 753 Ibid.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1078 of 1275 million in lifetime energy bill savings to 7,000 participating

households and 250 businesses. 754 Furthermore, direct bill assistance makes up 15% of cumulative investments, these investments have returned more than $140 million in bill savings to more than 2.4 million households, much of which is targeted

towards low income families. 755 In addition, the EPA encourages states in the writing of their plans to use other state models that help low income communities access the benefits of energy efficiency, renewable energy, and financial assistance programs. One example of such a program is The Maryland EmPOWER Low Income Energy Efficiency Program (LIEEP). 756 The LIEEP program administered by the Maryland Department of Housing and Community Development (DHCD) helps low income households through free installation of energy conservation materials (i.e., installation, hot water system improvements, lighting retrofits, furnace cleaning, tuning and safety repairs, refrigerator retrofits, etc.). 757 Funding for this program is provided by EmPOWER Maryland partners: Baltimore Gas and Electric, Southern Maryland Electric Cooperative,

754 Ibid. 755 Ibid. 756 EmPOWER Maryland Low Income Energy Efficiency Programs (LIEEP). http://www.mdhousing.org/website/Programs/lieep/Default.aspx. 757 Ibid.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1079 of 1275 Delmarva Power, Allegheny Energy and Pepco. 758 This program is

available to both homeowners and renters. 759 Additionally, the Maryland Department of Housing provides low income families with home heating bill assistance and furnace repairs and replacements through the Maryland Energy Assistance Program (MEAP). 760 Maryland’s Electric Universal Service Program (EUSP) helps low-income electric customers with their electric bills. 761 In the coming months, the EPA will continue to provide

information resources for affected communities and states on existing federal, state, local, and other financial assistance programs to encourage EE/RE that are already available to communities. The EPA will also 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 affected communities gain the benefits of this rulemaking by encouraging that states use these types of tools in their state plans. Additionally, the EPA recognizes the potential impacts that this rulemaking could have on jobs in communities. Therefore, in section VIII.H of this preamble, the EPA has outlined that

758 Ibid. 759 Ibid. 760 Energy Assistance. http://www.dhr.state.md.us/blog/?page_id=4326. 761 Ibid.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1080 of 1275 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 manifested. 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 (e.g., with regard to installing energy efficiency measures and rooftop solar panels). Additionally, as part of the resources that we will be providing to states and affected communities, the EPA will provide information on the White House’s Partnership for Opportunity and Workforce and Economic Revitalization (POWER) Initiative and other programs that specially targets economic development assistance to communities affected by changes in the coal industry and the utility power sector. 762

D. Co-pollutants As a result of this rulemaking, and as stated in section XI.F of this preamble, the EPA expects that most of America will benefit from improved air quality for PM 2.5 , ozone, and HAP, as well as greenhouse gases. Nonetheless, due to operational and efficiency changes, some affected EGUs may be dispatched more

762 http://www.eda.gov/power/.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1081 of 1275 intensively in the future than they were in the past. While the EPA will approve state plans, it is the states that have the ultimate responsibility to implement the guidelines of this rulemaking in order to meet their goals; as a result the EPA cannot predict localized emission increases or decreases. While there may be increases of co-pollutants at some facilities, it is important to remember that affected EGUs will still have to comply with other CAA rulemakings in addition to the guidelines in this final rulemaking. As noted in the NSR discussion in section X.A of this preamble, a state’s CAA section 111(d) plan may require an affected EGU to undertake physical or operational changes to improve its efficiency, which could result in an increase in the unit’s dispatch and an increase in the unit’s annual emissions of GHGs and/or other regulated pollutants. However, a state can take steps to avoid increased utilization of particular affected EGUs (i.e., dispatching other units) and associated emissions of regulated pollutants whose environmental

effects would be more localized around the affected EGU. To the extent that states take this path, there would be no disproportionate impacts in the areas near such affected EGUs. For those affected EGUs in a permitting situation for which the EPA is the permit reviewing authority, the EPA will consider*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1082 of 1275 environmental justice issues, as required by Executive Order

12898. Air quality in a given area, even in locations near emission sources, is influenced by emissions from nearby sources and in part by emissions that travel hundreds of miles and mix

with emissions from other sources. 763 In the Cross-State Air Pollution Rule the EPA used its authority to reduce emissions that significantly contribute to downwind exposures. The regulatory impact analysis for the final Cross-State Air Pollution Rule anticipates substantial health benefits for the population across a wide region. Therefore, the EPA believes that, like the Cross-State Air Pollution Rule, this rulemaking will result in significant health benefits because it will reduce co-pollutant emissions of SO 2 and NOx on a regional and

national basis. 764

Another effect of the final CO 2 emission guidelines for affected existing fossil fuel-fired EGUs will be increased utilization of other, unmodified EGUs - in particular high efficiency gas-fired EGUs - with relatively low GHG emissions per unit of electrical output. These plants will operate more hours during the year and could emit pollutants, including

763 76 FR 48348. 764 76 FR 48347.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1083 of 1275 pollutants whose environmental effects would be localized/and or regional rather than global as is the case with GHG emissions. Changes in utilization already occur in response to energy demands and evolving energy sources, but the final CO 2 emission guidelines for affected existing fossil fuel-fired EGUs can be expected to cause more such changes. Increased utilization generally would not increase peak concentrations of PM 2.5, NOx, or ozone around such EGUs to levels higher than those that are already occurring because peak hourly or daily emissions generally would not change; however, increased utilization may make periods of relatively high concentrations more frequent. It should be noted that the gas-fired sources likely to be dispatched more frequently have very low emissions of primary PM, SO 2, and HAP per unit of electrical output; therefore, local (or regional) air quality for these pollutants is not likely to be significantly affected. 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.” 765 Because gas-fired EGUs emit essentially no mercury, increased utilization will not increase methylmercury concentrations in water bodies near these affected

765 65 FR 79831.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1084 of 1275 EGUs. In studies done by DOE/NETL comparing cost and performance of coal- and NGCC-fired generation, they assumed SO 2 , NO X , PM (and Hg) emissions to be “negligible.” Their studies predict NOx emissions from a NGCC unit to be approximately 10 times lower than a subcritical or supercritical coal-fired boiler. 766 Many, although not all, NGCC units are also very well controlled for emissions of NOx through the application of after combustion controls such as selective catalytic reduction. Depending on the design of the state plan, the state may be able to predict which affected EGUs may increase generation and/or may cause increases in emissions and should address any concerns about localized NOx concentrations in the design of the CAA section 111(d) program, or separately from the CAA section 111(d) program planning process but before such program is implemented. Existing tracking systems will also allow states and the

EPA to be aware of affected EGUs whose utilization has increased most significantly, and to assess whether air quality has changed in the communities around such affected EGUs. There are multiple mechanisms in the CAA to address situations where there

766 “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity” Rev 2a, September 2013 Revision 2, November 2010 DOE/NETL-2010/1397.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1085 of 1275 is an existing air quality problem or where one may develop. Additionally, states will have to comply with the National Ambient Air Quality Standards (NAAQS) and other EPA rulemakings that come into effect during this same compliance period to protect public health and the environment.

E. EPA Continued Engagement The EPA is committed to helping ensure that this action will not have potential disproportionately high and adverse

human health or environmental effects on vulnerable communities. Throughout the implementation process of this rulemaking, the agency will continue to provide trainings and resources to assist affected communities and states as they engage with one another. In addition, the agency, through its outreach efforts during the implementation phase of this rulemaking, will

continue to solicit feedback from affected communities and states on topics for which they would like additional trainings

and resources. Additionally, the EPA will provide states with resources containing examples of analyses that other states have conducted to examine the impacts of their programs on communities. States can use this information to conduct analyses of their own if they so choose.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1086 of 1275 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.

F. Summary of Changes Made As described above, the EPA made several changes in this

Final rule that reflect comments from communities and other stakeholders. In response to such input, the EPA has conducted a proximity analysis for this rulemaking and provided the report in the docket. Additionally, the EPA has added a number of provisions in the state plan section that address community engagement and involvement throughout the implementation process. The EPA will continue outreach efforts and will continue to reach out to affected communities on topics that they are interested in learning more about. **X. Interactions with Other EPA Programs and Rules** A. Implications for the New Source Review Program The new source review (NSR) program is a preconstruction permitting program that requires major stationary sources of air*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1087 of 1275 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. For GHG emissions, the prevention of significant deterioration (PSD) applicability analysis is described in the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule (FR 75 31514, June 3, 2010). As a general matter, a modifying major stationary source would trigger PSD permitting requirements for GHGs if it emits GHGs in excess of 100,000 tons per year of carbon dioxide equivalents (CO 2 e), and it undergoes a change or change in the method of operation (modification) resulting in an emissions increase of 75,000 tons per year CO 2 e as well as an increase on a mass basis. Once it has been determined that a change triggers the requirements of the NSR program, the source must obtain a permit prior to making the change. The pollutant(s) at issue and the air quality designation of the area where the facility is*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1088 of 1275 located or proposed to be built determine the specific permitting requirements. 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 discussed above 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 emissions guidelines. One of these flexibilities is the ability of the state to establish the standards of performance 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1089 of 1275 comply with the standards of performance 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 adjust its demand-side measures or increase reliance on renewable energy 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). 767

767 Certain stationary sources that emit or have the potential to emit a pollutant at a level that is equal to or greater than specified thresholds are subject to major source requirements. See, e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic minor limitation is a legally and practicably enforceable restriction that has the effect of limiting*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1090 of 1275 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. B. Implications for the Title V Program 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

emissions below the relevant level and that a source voluntarily obtains to avoid major stationary source requirements, such as the PSD or title V permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 70.2 (definition of “potential to emit”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1091 of 1275 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 today’s Federal Registe r **[INSERT**

**THE FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE RULE]**  , the EPA is finalizing changes to the operating permits rules to address the title V fee issue. In particular, we are taking final action to exempt GHGs from emissions-based fee calculation requirements under the operating permit rules. In addition, we are also finalizing a modest GHG fee adjustment to recover the costs of addressing GHGs in permitting. The GHG adjustments we are finalizing are based on accounting for the number of permit actions that require a GHG assessment in a given period, rather than accounting for emissions levels of GHGs. Finally, the EPA is also finalizing the 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) 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 2 , becomes subject to regulation under CAA section

111 for the first time.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1092 of 1275 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 today’s Federal Register ). The title V fee issue is not an issue for any other subsequent CAA section 111 regulations, such as this section 111(d) standard; thus, there is no need to address any title V fee issues in this final rule as part of this action. 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 United States Supreme Court issued its opinion in UARG v EPA , 134 S.Ct. 2427 (June 23, 2014), and in accordance with that decision, the D.C. Circuit subsequently issued an amended judgment in Coalition for Responsible Regulation, Inc. v. Environmental Protection Agency , Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015). Those decisions support the same overall conclusion, as the EPA discussed in the proposal, with respect to the effect of this final section 111 rule on the applicability thresholds for GHGs under the operating permits rules, though for different

reasons.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1093 of 1275 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 UARG v. EPA , and, if so, to undertake to make such revisions. These court decisions make clear that promulgation of CAA section 111 requirements for GHGs will not result in EPA imposing a requirement that stationary sources obtain a title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds.

C. Interactions with Other EPA Rules Fossil fuel-fired EGUs are, or potentially will be, impacted by several other recently finalized or proposed EPA

rules. 768 The EPA recognizes the importance of assuring that each

768 We discuss other rulemakings solely for background purposes. The effort to coordinate rulemakings is not a defense to a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1094 of 1275

of the rules described below 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 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. Each 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. 1. Mercury and Air Toxics Standards (MATS) 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

violation of the CAA. Sources cannot defer compliance with existing requirements because of other upcoming regulations.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1095 of 1275 suspected of causing, damage nervous system damage, cancer, and

other serious health effects. The MATS rule will also reduce SO 2 and fine particle pollution, which will reduce particle concentrations in the air and prevent thousands of premature deaths and tens of thousands of heart attacks, bronchitis cases and asthma episodes. New or reconstructed EGUs (i.e., sources that commence construction or reconstruction after May 3, 2011) subject to the MATS rule are required to comply by April 16, 2012 or upon startup, whichever is later. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1096 of 1275 to an additional year, if it is needed to ensure electricity reliability. 2. Cross-State Air Pollution Rule (CSAPR) The CSAPR requires states to take action to improve air quality by reducing SO 2 and NO X emissions that cross state lines. These pollutants react in the atmosphere to form fine particles and ground-level ozone and are transported long distances, making it difficult for other states to attain and maintain the NAAQS. The first phase of CSAPR became effective on January 1, 2015, for SO 2 and annual NO X , and May 1, 2015, for ozone season

NO X . The second phase will become effective on January 1, 2017,

for SO 2 and annual NO x , and May 1, 2017, for ozone season NO x . Many of the power plants participating in CSAPR have taken actions to reduce hazardous air pollutants for MATS compliance

that will also reduce SO 2 and/or NO x . In this way these two rules are complementary. Compliance with one helps facilities comply

with the other. 3. Requirements for Cooling Water Intake Structures at Power Plants (316(b) Rule) On May 19, 2014, the EPA issued a final rule under section 316(b) of the Clean Water Act (CWA) (33 U.S.C. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1097 of 1275 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. 769 The 316(b) rule subjects existing power plants and manufacturing facilities that withdraw in excess of 2 million gallons per day) of cooling water, and use at least 25 percent of that water for cooling purposes, to a national standard designed to reduce the number of fish destroyed through impingement and a national standard for establishing entrainment reduction requirements. All facilities subject to the rule must submit information on their operations for use by the permit authority in determining 316(b) permit conditions. Certain plants that withdraw very large volumes of water will also be required to conduct additionalstudies for use by the permit authority in determining the sitespecific entrainment reduction measures for such facilities. The rule provides significant flexibility for compliance with the impingement standards and, as a result, is not projected to impose a substantial cost burden on affected facilities. With respect to entrainment, the rule calls upon the permitting

769 CWA section 316(b) provides that standards applicable to point sources under sections 301 and 306 of the Act must require that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1098 of 1275 authority to establish appropriate entrainment reduction measures, taking into account, among other factors, remaining useful plant life and quantified and qualitative social benefits and cost. The permit writer may also consider impacts on the reliability of energy delivery within the facility’s immediate area. Existing sources subject to the 316(b) rule are required to comply with the impingement requirements as soon as practicable after the entrainment requirements are determined. They must comply with applicable site-specific entrainment reduction controls based on the schedule of requirements established by the permitting authority. 4. Disposal of Coal Combustion Residuals from Electric Utilities (CCR Rule) 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 new CCR landfills and surface impoundments under Subtitle D of the Resource*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1099 of 1275 Conservation and Recovery Act, the nation's primary law for regulating solid waste. 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 website. The final rule also supports the responsible recycling of CCRs by distinguishing safe, beneficial use from disposal.

5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG Rule) 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1100 of 1275 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 United States 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 (e.g., by facilitating their ability to coordinate planning and investment decisions with respect to those rules) and, where possible, implement integrated compliance strategies. For example, in the proposed SE ELG rule,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1101 of 1275 the EPA describes its thinking on how it might effectively harmonize the potential requirements of that rule with the requirements of the final CCR rule. Because these two rules affect similar units and may be met with similar compliance strategies, common-sense implementation timeframes were

established in the CCR final rule so that utilities would not be required to make major decisions about CCR units without first understanding the implications that such decisions would have for meeting the surface water protection requirements of the final ELG rule. The EPA is taking into account these new CCR requirements for coal ash as it develops the final SE ELG rule. The EPA's goal in harmonizing the SE ELG and CCR rules is to minimize the overall complexity of the two regulatory structures and avoid creating unnecessary burden

. 6. Other EPA Rules In addition to the power sector rules discussed above, the development of SIPs for criteria pollutants (ozone, PM 2.5 , and

SO 2 ) and regional haze may also have implications for existing

fossil-fired EGUs. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1102 of 1275 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 Federal Register on December 17, 2014 (79 FR 75234). The Administrator proposed to revise the primary ozone standard to a level in the range of 0.065 to 0.070 ppm and took comment on lower levels including 0.060 ppm and on retaining the current standard of 0.075 ppm. Among other things, the ozone NAAQS proposal also proposed to retain the current indicator, averaging time, and form of the standard and included a proposed secondary ozone NAAQS in the 0.065 to 0.070 ppm

range.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1103 of 1275 The proposal also outlined the key implementation milestones requiring revised state implementation plans, 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) emissions 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) emissions guidelines proposal, commenters expressed a desire for the EPA to coordinate promulgation of the final 111(d) emissions 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1104 of 1275 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 2.5 NAAQS implementation, the proposal stated that the EPA was developing a proposed implementation rule to provide guidance to states on the development of SIPs for the

2012 PM 2.5 NAAQS. The proposed PM 2.5 SIP requirements rule was signed on March 10, 2015, and published on March 23, 2015 (80 FR 15340). The proposal addresses a number of requirements including attainment plan due dates, attainment dates and

attainment date extension criteria for Moderate and Serious nonattainment areas; determination criteria for Reasonably Available Control Measures (RACM) for Moderate areas and Best Available Control Measures (BACM) for Serious areas; plans for demonstrating reasonable further progress and for meeting periodic quantitative milestones; and criteria for reclassifying a Moderate nonattainment area to Serious. The EPA is planning to

finalize the PM 2.5 implementation rule in early 2016.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1105 of 1275 There are currently only 9 areas designated nonattainment

for the 2012 PM 2.5 NAAQS, with an effective date of April 15, 2015. Since the attainment plans for these areas must be completed and submitted to the EPA in September 2016, we expect that the four states with such areas should have already decided on their approach to implementing the 2012 PM 2.5 NAAQS when they begin to develop their plans for implementing the 111(d) guidelines, and will be able to coordinate the two.

Related to the SO 2 NAAQS, and as stated in the proposal, the

SO 2 NAAQS was revised in June 2010 to protect public health from

the short-term effects of SO 2 exposure. In July 2013, the EPA designated 29 areas in 16 states as nonattainment for the SO 2 NAAQS. The EPA based these nonattainment designations on the most recent set of certified air quality monitoring data as well as an assessment of nearby emission sources and weather patterns

that contribute to the monitored levels. The date for attainment plans for these areas to be completed and submitted to the EPA was April 2015. As such, we expect states with such areas to have already decided on their approach to implementing the SO 2 NAAQS as they start planning for implementation of the 111(d) guidelines, which should allow for coordination and

consideration of SO 2 related air quality measures into their 111(d) planning. The EPA intends to address the designations for*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1106 of 1275 all other areas in three separate actions in the future. 770 These designations must be completed by no later than July 2, 2016, December 31, 2017, and December 31, 2020 with attainment plans

due between 2018 and 2022. 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.

770 The EPA has developed a comprehensive implementation strategy for these future actions that focuses resources on identifying and addressing unhealthy levels of SO 2 in areas where people are most likely to be exposed to violations of the standard. The strategy is available at http://www.epa.gov/airquality/sulfurdioxide/implement.html, and the associated area designations schedule is at http://www.epa.gov/airquality/sulfurdioxide/designations/pdfs/20 1503Schedule.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1107 of 1275 While the EPA is providing considerable flexibility for states and sources under the final 111(d) emissions 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. 771 The EPA will continue to work with states to explore options for integrating compliance requirements across multiple regulatory programs, as warranted.

771 For example, Oregon replaced its BART determination for the Boardman Coal Plant with a new requirement that accounted for a planned shutdown before the EPA took action on the state’s SIP submission (76 FR 12661). Washington similarly replaced its BART determination for the TransAlta Centralia Power Plant before the EPA took action on the state’s SIP submission (77 FR 72742). Oklahoma submitted a SIP revision with a new BART determination for the AEP/PSO Northeastern Power Station, which included enforceable requirements for reduced utilization and early unit retirements, to replace a FIP that had been promulgated by the EPA (79 FR 12944). Finally, the EPA finalized a BART determination for Unit 3 at the Dave Johnston Power Plant in Wyoming that included two compliance options, one of which included a federally enforceable retirement date and less costly controls.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1108 of 1275 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.

7. Final Rule Flexibilities 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 2 emission reduction measures, including measures that are not part of the BSER. The EPA is also providing states considerable flexibility with respect to the timeframes for plan development and implementation, with up to 3 years permitted for final plans to be submitted after the GHG emission guidelines are finalized, and up to 15 years for all emission reduction measures to be fully implemented. The EPA is establishing an 8-year interim period over which to achieve the full required reductions to

meet the CO 2 performance rates, and this begins in 2022, more than seven years from the June 18, 2014 date of proposal of the rulemaking. The 8-year interim period from 2022 through 2029, is separated into three steps, 2022-2024, 2025-2027, and 2028-2029,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1109 of 1275

each associated with its own interim CO 2 emission performance

rates. 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. 772 We also believe that the

broad flexibilities in this action will enable states and affected EGUs to build on their longstanding, successful records of complying with multiple CAA, CWA, and other environmental

772 It should be noted that regulatory obligations imposed upon states and sources operate independently under different statutes and sections of statutes; the EPA expects that states and sources will take advantage of available flexibilities as appropriate, but will comply with all relevant legal requirements.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1110 of 1275 requirements, while assuring an adequate, affordable, and reliable supply of electricity. **XI. Impacts of the Final Action 773** 

A. What are the air impacts? The EPA anticipates significant emission reductions under the final guidelines for the utility power sector. When compared to 2005, CO 2 emissions are projected to be reduced by approximately [X] percent in 2020, [X] percent in 2025, and [X] percent in 2030. The final guidelines are projected to result in substantial co-benefits through reductions of SO 2 , PM 2.5 and NO X that will have direct public health benefits by lowering ambient levels of these pollutants and ozone. Table 11 shows expected CO 2 and other air pollutant emissions in the base case and reductions under the final guidelines for 2020, 2025, and 2030. **Table 11. Summary of CO 2**  **and Other Air Pollutant Emission Reductions under Final Guidelines**  **CO 2**  **(million**

**metric**

**tons) SO**  **2 (**  **thousands**

**of tons) NO**  **X (**  **thousands**

**of tons) PM**  **2.5 (thousands** 

**of tons) 2020 Final Guidelines** 

773 The impacts presented in this section of the preamble represent an illustrative implementation of the guidelines. As states implement the final guidelines, they have sufficient flexibility to adopt different state-level or regional approaches that may yield different costs, benefits, and environmental impacts. For example, states may use the flexibilities described in these guidelines to find approaches that are more cost effective for their particular state or choose approaches that shift the balance of co-benefits and impacts to match broader state priorities.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1111 of 1275

Base Case [X] [X] [X] [X] Final Guidelines [X] [X] [X] [X] Emissions Reductions [X] [X] [X] [X] **2025 Final Guidelines** Base Case [X] [X] [X] [X] Final Guidelines [X] [X] [X] [X] Emissions Reductions [X] [X] [X] [X] **2030 Final Guidelines** Base Case [X] [X] [X] [X] Final Guidelines [X] [X] [X] [X] Emissions Reductions [X] [X] [X] [X] Source: Integrated Planning Model, 2015.

The reductions in Table 11 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. B. Endangered Species Act 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1112 of 1275 7(a)(2) would not be triggered by promulgation of the rule, and

we now finalize that determination in this final rule. 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 section 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. See 51 FR 19926, 19949 (June 3, 1986). Effects of an

action include both the direct and indirect effects that will be

added to the environmental baseline. 50 CFR 402.02. Indirect effects are those that are caused by the action, later in time, and are reasonably certain to occur. Id. To trigger a*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1113 of 1275 consultation requirement, there must thus be a causal connection between the federal action, the effect in question, and the listed species, and the effect must be reasonably certain to

occur. 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 2 and NO X ). However, the fact that the rule will have overall positive effects on the environment does not mean that the rule may affect any listed species or designated critical habitat within the meaning of ESA section 7(a)(2) or the implementing regulations or require ESA consultation. The EPA has considered various types of potential effects in reaching the conclusion that ESA consultation is not required for this rule. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1114 of 1275

insufficient to draw a causal connection between GHG emissions and effects on the species in its habitat. 774 The DOI Solicitor concluded that where the effect at issue is climate change, proposed actions involving GHG emissions cannot pass the “may affect” test of the section 7 regulations and thus are not subject to ESA consultation. The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2). Although the GHG emission reductions projected for this final rule are large (estimated reductions of [X] million metric

tons of CO 2 in 2030 – see Table 11 above), the EPA evaluated larger reductions in assessing 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 emission reductions roughly double and four times those projected here over the lifetimes of the model years in question 775 and, based on air quality modeling of potential environmental effects, concluded that “EPA knows of no modeling tool which can link

774 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from David Longly Bernhardt, Solicitor, U.S. Department of the Interior re: ‘‘Guidance on the Applicability of the Endangered Species Act’s Consultation Requirements to Proposed Actions Involving the Emission of Greenhouse Gases’’ (Oct. 3, 2008).

775 See 75 FR at 25438 Table I.C 2–4 (May 7, 2010); 77 FR at 62894 Table III–68 (Oct. 15, 2012).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1115 of 1275 these small, time-attenuated changes in global metrics to particular effects on listed species in particular areas. Extrapolating from global metric to local effect with such small numbers, and accounting for further links in a causative chain, remain beyond current modeling capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel Economy Standards, Response to Comment Document for Joint Rulemaking at 4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion after evaluating issues relating to potential improvements relevant to both temperature and oceanographic pH outputs. The EPA's ultimate finding was that “any potential for a specific impact on listed species in their habitats associated with these very small changes in average global temperature and ocean pH is too remote to trigger the threshold for ESA section 7(a)(2).” Id. The EPA believes that the same conclusion applies to the present rule, given that the projected CO 2 emission reductions are less than those projected for either of the light duty vehicle rules. See, e.g., Ground

Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a species from a federal action is extremely remote, ESA does not require consultation).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1116 of 1275 With regard to non-GHG air emissions, the EPA also projects

substantial reductions of SO 2 and NO X as a collateral consequence of this final action. However, CAA section 111(d)(1) standards cannot directly control emissions of criteria pollutants. Consequently, CAA section 111(d) provides no discretion to adjust the standard based on potential impacts to endangered species of reduced criteria pollutant emissions. Section 7(a)(2) consultation thus is not required with respect to the projected reductions of criteria pollutant emissions. See 50 CFR 402.03; see also, WildEarth Guardians v. U.S. Envt’l Protection Agency, 759 F.3d 1196, 1207-10 (10th Cir. 2014) (EPA has no duty to consult under section 7(a)(2) of the ESA regarding hazardous air pollutant controls that it did not require – and likely lacked authority to require – in a federal implementation plan for regional haze controls under section 169A of the CAA); National

Lime Ass'n v. EPA, 233 F. 3d 625, 638-39 (D.C. Cir. 2000) (although CAA section 112(b)(2) prohibits the EPA from listing criteria pollutants as hazardous air pollutants, the EPA may use PM as a surrogate for metal hazardous air pollutants and reductions in PM do not constitute impermissible regulation of a criteria pollutant). Finally, the EPA has also considered other potential effects of the rule (beyond reductions in air pollutants) and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1117 of 1275 whether any such effects are sufficiently certain to call for ESA consultation. 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. Cf. American Trucking Assn's v. EPA, 175 F. 3d 1027, 1043-45 (D.C. Cir. 1999), rev'd on different grounds sub nom., Whitman v. American Trucking Assn's, 531 U.S. 457 (2000) (National Ambient Air Quality Standards have no economic impact, for purposes of Regulatory Flexibility Act, because impacts result from the actions of states through their development, implementation and enforcement of state implementation plans). The EPA recognized, for instance, that questions may exist whether decisions such as increased utilization of solar or wind power could have effects on listed species. The EPA received comments on the proposal asserting that because potential increased reliance on wind or solar power may be an element of Building Block 3, and because wind and solar facilities may in some cases have effects on listed species, the EPA must consult under the ESA on this aspect of the rule. The EPA is also aware of certain questions posed by a Member of the U.S. House of Representatives to FWS*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1118 of 1275 regarding potential effects of the rule on the Big Bend Power Station located in Florida, which discharges effluent that provides a warm water refuge for manatees. 776 The EPA does not believe that the effects of potential future changes in the energy sector – including increased reliance on wind or solar power – or any potential alterations in the operations of any particular facility are 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 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

776 See Letter from Rob Bishop, Chairman, Committee on Natural Resources, to Dan Ashe, Director, U.S. Fish and Wildlife Service, dated April 2, 2015.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1119 of 1275 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 precise steps included in an implementation plan cannot be determined or ordered by this federal action, and they are not sufficiently certain to be attributable to this final rule for ESA purposes. These steps will flow from a series of later in time decisions made in the planning process, which cannot now be predicted with reasonable certainty or required by the rule. The EPA notes that many of these decisions will be made by other entities, most likely states. The EPA also notes that the plans adopted for particular states may themselves provide wide degrees of implementation flexibility, thus further increasing the uncertainty that any species-impacting activity will occur in any particular location, if at all. The Services have explained that section 7(a)(2) was not intended to preclude federal actions based on potential future speculative effects. 777 These

777 See 51 FR at 19933 (describing effects that are “reasonably certain to occur” in the context of consideration of cumulative effects and distinguishing broader consideration that may be appropriate in applying a procedural statute such as the National Environmental Policy Act, as opposed to a substantive provision such as ESA section 7(a)(2) that may prohibit certain federal actions); Endangered Species Consultation Handbook, U.S. Fish & Wildlife Service and National Marine Fisheries Service*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1120 of 1275 are precisely the types of speculative future activities and

effects at issue here. 778 For this additional reason, the EPA concludes that the rule does not have effects on listed species that trigger the section 7(a)(2) consultation requirement. C. What are the energy impacts? The final guidelines have important energy market implications. Under the final guidelines, average nationwide retail electricity prices are projected to increase/decrease about [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030 for the contiguous U.S., relative to the base case. Average monthly electricity bills are anticipated to increase/decrease about [X]

(March 1998) (in the same context, describing indicators that an activity is reasonably certain to occur as including governmental approvals of the action or indications that such approval is imminent, project sponsors’ assurance that the action will proceed, obligation of venture capital, or initiation of contracts; and noting that the more governmental administrative discretion remains to be exercised, the less there is reasonable certainty the action will proceed). 778 EPA also notes that some of the future implementing activities themselves may require ESA consultation, thus providing consideration of any impacts on listed species at the appropriate point when particular activities have become reasonably certain. Several commenters on the proposal specifically noted that such future activities – e.g. , development of additional renewable energy facilities such as wind farms – may call for ESA consultation. Further, EPA notes that section 9 of the ESA, which prohibits the take of individuals of most listed species, provides an additional protection for listed species as future implementing activities become reasonably certain.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1121 of 1275 percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030, relative to the base

case. Under the final guidelines, the average delivered coal price to the utility power sector is projected to increase/decrease about [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030, relative to the base case. The EPA projects coal use by the utility power sector, a large component of total coal use, will increase/decrease approximately [X] percent in 2020, increase/decrease[X] percent in 2025, and increase/decrease [X] percent in 2030 from base case levels. The EPA also projects that utility power sector-delivered natural gas prices will increase/decrease about [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030. Natural gas use for electricity generation will increase/decrease about [X] trillion cubic feet (TCF) in 2020, increase/decrease [X] TCF in 2025, and increase/decrease [X] TCF in 2030 relative to the base case. Renewable energy capacity is anticipated to increase by roughly [X] GW in 2025 and [X] GW in 2030 under the final guidelines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1122 of 1275 These figures reflect the EPA’s illustrative modeling that presumes policies that lead to generation shifts and growing use of demand-side energy efficiency 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 energy efficiency 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. D. What are the compliance costs? 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-*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1123 of 1275 side energy efficiency. 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 demandside energy efficiency programs, and other actions associated with compliance. These important dynamics are discussed in more detail in the RIA in the rulemaking docket. The EPA projects that the annual incremental compliance cost of the final guidelines is estimated to be $[X] billion in 2020, about $[X] billion in 2025, and about $[X] billion (2011$)

in 2030. These estimates also include the costs associated with monitoring, reporting, and recordkeeping (MRR). MRR costs are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1124 of 1275 estimated to be approximately $[X] million in 2020, $[X] million in 2025, and $[X] million (2011$) in 2030. More detailed cost estimates are available in the RIA included in the rulemaking

docket. E. What are the economic and employment impacts? The final standards are projected to result in certain changes to power system operation as a compliance with the standards. Overall, we project generation shifts, changes to fossil fuel and retail electricity prices, and some additional coal-fired EGU retirements. Average utility power sector delivered natural gas prices are projected to increase/decrease roughly [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030 under the final guidelines, on a nationwide average basis. The average delivered coal price to the utility power sector is projected to increase/decrease about [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] percent in 2030 under the final guidelines, on a nationwide average basis. Retail electricity prices are projected to increase/decrease [X] percent in 2020, increase/decrease [X] percent in 2025, and increase/decrease [X] in 2030 on an average basis across the contiguous U.S. Under the final guidelines, the EPA projects [X]*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1125 of 1275 GW of additional coal-fired generation may be uneconomic to maintain and may be removed from operation by 2030. 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. By 2025, the average age of the coal-fired fleet will be 49 years old and 20 percent of the fleet will be more than 60 years old if they remain in operation at that time. 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 statesramp up programs that result in lower overall demand. Demandside energy efficiency levels are expected to increase such that they achieve about an [X] 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1126 of 1275 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 energy efficiency 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. During the current economic recovery, 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1127 of 1275 by the wide range of approaches that states may use. As such, the EPA’s employment analysis includes projected employment impacts associated with illustrative compliance scenarios for these guidelines for the electric power industry, coal and natural gas production, and demand-side energy efficiency 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 utility power, coal, and natural gas sectors, the EPA estimates that these guidelines could have anemployment impact of roughly [X] job-years in [20XX], [X] jobyears in [20XX], and [X] job-years in [20XX]. Demand-side energy efficiency employment impacts are estimated at approximately an increase of [X] jobs in 2020, [X] jobs in 2025, and [X] jobs in 2030. By its nature, demand-side energy efficiency 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1128 of 1275 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. F. What are the benefits of the final goals? Implementing the final standards will generate benefits by reducing emissions of CO 2 and criteria pollutant precursors, including SO 2 , NO X , and directly emitted particles. SO 2 and NO X are precursors to PM 2.5 (particles smaller than 2.5 microns), and

NO X is a precursor to ozone. The estimated benefits associated with these emission reductions are beyond those achieved by previous EPA rulemakings including the Mercury and Air Toxics Standards rule. The health and welfare benefits from reducing air pollution are considered co-benefits for these standards. For this rulemaking, we were only able to quantify the climate

benefits from reduced emissions of CO 2 and the health co-benefits*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1129 of 1275 associated with reduced exposure to PM 2.5 and ozone. There are many additional benefits which we are not able to quantify, leading to an underestimate of monetized benefits. In summary,

we estimate the total combined climate benefits and health cobenefits to be $[X] to $[X] billion in 2020, $[X] to $[X] billion in 2025, and $[X] to $[X] billion in 2030 (3 percent discount rate, 2011$). A summary of the emission reductions and

monetized benefits estimated for this rule at all discount rates is provided in Tables 12 through 14 of this preamble.

**Table 12. Summary of the Monetized Global Climate Benefits for the Final Guidelines (billions of 2011$)**  **a Discount Rate** 

**(Statistic) Monetized Climate Benefits** 

**YEAR 2020 2025 2030**  **CO 2**  **Reductions (million**  **metric tons)** [X] [X] [X]

5 percent (average SC-CO 2 ) $[X] $[X] $[X] 3 percent (average SC-CO 2 ) $[X] $[X] $[X] 2.5 percent (average SC-CO 2 ) $[X] $[X] $[X]

3 percent (95 th percentile SC-CO 2 ) $[X] $[X] $[X]

a Climate benefit estimates reflect impacts from CO 2 emission changes in the analysis years presented in the table and do not account for changes in non-CO 2 GHG emissions. These estimates are*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1130 of 1275 based on the global social cost of carbon (SC-CO 2 ) estimates for the analysis years and are rounded to two significant figures.

**Table 13. Summary of the Monetized Health Co-Benefits in the U.S. for the Final Guidelines (billions of 2011$)**  **a**

**Pollutant National**  **Emission R**  **eductions (**  **thousands**

**of short tons)**  **Monetized Health Co** 

**benefits Monetized** **Health Co**

**benefits (3 percent**  **discount) (7 percent**  **discount) Final Guidelines, 2020**  **PM 2.5**  **precursors b**  **SO 2**  [X] $[X] to $[X] $[X] to $[X] **Directly emitted PM 2.5**  **(Elemental Carbon and Organic Carbon)**  [X] $[X] $[X]

**Directly emitted PM 2.5**  **(crustal)** [X] $[X] $[X]

**NO X**  [X] $[X] to $[X] $[X] to $[X] **Ozone precursor c** 

**NO X**  **(ozone season only)** [X] $[X] to $[X] $[X] to $[X]

**Total Monetized Health Co-benefits** $[X] to $[X] $[X] to $[X] **Total Monetized Health Co -**  **b enefits**  **combined with Monetized Climate Benefits**  **d** $[X] to $[X] $[X] to $[X] **Final Guidelines, 2025 PM**  **2.5 precursors**  **b SO**  **2** [X] $[X] to $[X] $[X] to $[X] **Directly emitted PM 2.5**  **(Elemental Carbon and Organic Carbon)**  [X] $[X] $[X]

**Directly emitted PM 2.5**  **(crustal)** [X] $[X] $[X]

**NO X**  [X] $[X] to $[X] $[X] to $[X]*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1131 of 1275

**Ozone precursor c** 

**NO X**  **(ozone season only)** [X] $[X] to $[X] $[X] to $[X]

**Total Monetized Health Co-benefits** $[X] to $[X] $[X] to $[X] **Total Monetized Health Co -**  **b enefits**  **combined with Monetized Climate Benefits**  **d** $[X] to $[X] $[X] to $[X] **Final Guidelines, 2030 PM**  **2.5 precursors**  **b SO**  **2** [X] $[X] to $[X] $[X] to $[X] **Directly emitted PM**  **2.5 (Elemental Carbon**  **and Organic Carbon)** [X] $[X] $[X]

**Directly emitted PM**  **2.5 (crustal)**  [X] $[X] $[X]

**NO X**  [X] $[X] to $[X] $[X] to $[X] **Ozone precursor c**  **NO X**  **(ozone season only)**  [X] $[X] to $[X] $[X] To $[X]

**Total Monetized Health Co-benefits** $[X] to $[X] $[X] to $[X] **Total Monetized Health Co -**  **b enefits**  **combined with Monetized Climate Benefits**  **d** $[X] to $[X] $[X] to $[X]

a All estimates are rounded to two significant figures, so estimates may not sum. It is important to note that the monetized co-benefits do not include reduced health effects from direct exposure to SO 2 , direct exposure to NO 2 , exposure to mercury, ecosystem effects or visibility impairment. Air pollution health co-benefits are estimated using regional benefit-per-ton estimates for the contiguous U.S. b The monetized PM 2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM 2.5 through reductions of PM 2.5 precursors, such as SO 2 , NO X and directly emitted PM 2.5 . PM co-benefits are shown as a range reflecting the use of two concentration-response functions, with the lower end of the range based on a function from Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume that all fine particles, regardless of their*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1132 of 1275 chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.

c The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone through reductions of NO X during the ozone season. Ozone co-benefits are shown as a range reflecting the use of several different concentration-response functions, with the lower end of the range based on a function from Bell, et al. (2004) and the upperend based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for all discount rates. d We estimate climate benefits associated with four different values of a one ton CO 2 reduction (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). Referred to as the social cost of carbon, each value increases over time. For the purposes of this table, we show the benefits associated with the model average at 3 percent discount rate, however we emphasize the importance and value of considering the full range of social cost of carbon values. We provide combined climate and health estimates based on additional discount rates in the RIA.

The EPA has used the social cost of carbon (SC-CO 2 ) estimates presented in the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (May 2013, Revised June 2015) (“current TSD”) to analyze CO 2 climate impacts of this rulemaking. 779 We refer to these estimates, which were developed

779 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental Protection Agency, National Economic Council,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1133 of 1275 by the U.S. government, as “SC-CO 2 estimates.” The SC-CO 2 is a metric that estimates the monetary value of impacts associated with marginal changes in CO 2 emissions in a given year. It includes a wide range of anticipated climate impacts, such as net changes in agricultural productivity and human health, property damage from increased flood risk, and changes in energy system costs, such as reduced costs for heating and increased costs for air conditioning. It is typically used to assess the avoided damages as a result of regulatory actions (i.e., benefits of rulemakings that lead to an incremental reduction in cumulative global CO 2 emissions).

The SC-CO 2 estimates used in this analysis were developed over many years, using the best science available, and with input from the public. Specifically, an interagency working group (IWG) that included the EPA and other executive branch agencies and offices used three integrated assessment models (IAMs) to develop the SC-CO 2 estimates and recommended four global values for use in regulatory analyses. The SC-CO 2 estimates were first released in February 2010 and updated in 2013 using new versions of each IAM. The 2010 SC-CO 2 Technical

Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury (May 2013, Revised June 2015). Available at: http://[X].*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1134 of 1275 Support Document (2010 TSD) 780 provides a complete discussion of the methods used to develop these estimates and the current TSD presents and discusses the 2013 update (including two recent minor corrections to the estimates). 781

The EPA received numerous comments on the SC-CO 2 estimates as part of this rulemaking. The comments covered a wide range of topics including the technical details of the modeling conducted to develop the SC-CO 2 estimates, the aggregation and presentation

of the SC-CO 2 estimates, and the process by which the SC-CO 2 estimates were derived. Many but not all commenters were

780 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon , with participation by the Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Environmental Protection Agency, National Economic Council, Office of Energy and Climate Change, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury (February 2010). Also available at:http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf.

781 The current version of the TSD is available at: http://[X], Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, with participation by Council of Economic Advisers, Council on Environmental Quality, Department of Agriculture, Department of Commerce, Department of Energy, Department of Transportation, Domestic Policy Council, Environmental Protection Agency, National Economic Council, Office of Management and Budget, Office of Science and Technology Policy, and Department of Treasury (May 2013, Revised June 2015).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1135 of 1275 supportive of the SC-CO 2 and its application to this rulemaking. Commenters also provided constructive recommendations for potential opportunities to improve the SC-CO 2 estimates in future updates. Many of these comments were similar to those that OMB’s Office of Information and Regulatory Affairs received in response to a separate 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 interagency working group continues to recommend the use of the SC-CO 2 estimates in regulatory impact analysis. With the release of the response to comments, the interagency working group announced plans to obtain expert independent advice from the National Academy of Sciences’ National Research Council (NRC) to ensure

that the SC-CO 2 estimates continue to reflect the best available scientific and economic information on climate change. The NRC review will be informed by the public comments received and focus on the technical merits and challenges of potential approaches to improving the SC-CO 2 estimates in future updates. See the EPA Response to Comments document for the complete response to comments received on SC-CO 2 as part of this rulemaking. Concurrent with OMB’s publication of the response to

comments on SC-CO 2 and announcement of the NRC process, OMB*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1136 of 1275 posted a revised TSD that includes two minor technical

corrections to the current estimates. One technical correction addressed an inadvertent omission of climate change damages in the last year of analysis (2300) in one model and the second addressed a minor indexing error in another model. On average

the revised SC-CO 2 estimates are one dollar less than the mean

SC-CO 2 estimates reported in the November 2013 revision to the May 2013 TSD. The change in the estimates associated with the 95th percentile estimates when using a 3 percent discount rate is slightly larger, as those estimates are heavily influenced by the results from the model that was affected by the indexing

error.

The four SC-CO 2 estimates are as follows: $13, $45, $66, and $130 per metric ton of CO 2 emissions in the year 2020 (2011$). 782 The first three values are based on the average SC-CO 2 from the three IAMs, at discount rates of 5, 3, and 2.5 percent, respectively. The SC-CO 2 value at several discount rates are

included because the literature shows that the SC-CO 2 is quite sensitive to assumptions about the discount rate, and because no consensus exists on the appropriate rate to use in an

782 The 2010 and 2013 TSDs present SC-CO 2 in $2007. The estimates were adjusted to 2011$ using the GDP Implicit Price Deflator. Also available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013- 02/pdf/ECONI-2013-02-Pg3.pdf.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1137 of 1275 intergenerational context (where costs and benefits are incurred by different generations). The fourth value is the 95 th percentile of the SC-CO 2 from all three models at a 3 percent discount rate. It is included to represent higher-than-expected impacts from temperature change further out in the tails of the

SC-CO 2 distribution (representing less likely, but potentially catastrophic, outcomes).

There are limitations in the estimates of the benefits from the final emission guidelines, including the omission of climate

and other CO 2 related benefits that could not be monetized. The

2010 TSD discusses a number of limitations to the SC-CO 2 analysis, including the incomplete way in which the IAMs capture catastrophic and non-catastrophic impacts, their incomplete treatment of adaptation and technological change, uncertainty in the extrapolation of damages to high temperatures, and assumptions regarding risk aversion. Currently, IAMs do not assign value to all of the important impacts of CO 2 recognized in the literature, such as ocean acidification or potential tipping points, for various reasons, including the inherent difficulties in valuing non-market impacts and the fact that the science incorporated into these models understandably lags behind the most recent research. Nonetheless, these estimates and the discussion of their limitations represent the best available*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1138 of 1275

information about the social benefits of CO 2 emission reductions to inform the benefit-cost analysis. As previously noted, the interagency working group plans to seek independent expert advice on technical opportunities to improve the SC-CO 2 estimates from the NRC. The NRC process will help to ensure that the SC-CO 2 estimates used by the federal government continue to reflect the best available science and methodologies. Additional details are provided in the TSDs. The health co-benefits estimates represent the total monetized human health benefits for populations exposed to

reduced PM 2.5 and ozone resulting from emission reductions from the illustrative compliance strategy for the final standards. Unlike the global SC-CO 2 estimates, the air pollution health cobenefits are estimated for the contiguous U.S. only. We used a “benefit-per-ton” approach to estimate the benefits of this rulemaking. To create the PM 2.5 benefit-per-ton estimates, we conducted air quality modeling for an illustrative scenario reflecting the proposed standards to convert precursor emissions into changes in ambient PM 2.5 and ozone concentrations. We then used these air quality modeling results in BenMAP 783 to calculate average regional benefit-per-ton estimates using the health

783 http://www.epa.gov/airquality/benmap/index.html*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1139 of 1275 impact assumptions used in the PM NAAQS RIA 784 and Ozone NAAQS

RIAs. 785,786 The three regions were the Eastern U.S., Western U.S.,

and California. To calculate the co-benefits for the final standards, we multiplied the regional benefit-per-ton estimates generated from modeling of the proposed standards by the corresponding regional emission reductions for the final

standards. 787 All benefit-per-ton estimates reflect the geographic distribution of the modeled emissions for the proposed standards, which may not exactly match the emission

784 U.S. Environmental Protection Agency (U.S. EPA). 2012. Regulatory Impact Analysis for the Final Revisions to the National Ambient Air Quality Standards for Particulate Matter

. Research Triangle Park, NC: Office of Air Quality Planning and Standards, Health and Environmental Impacts Division. (EPA document number EPA-452/R-12-003, December). Available at: <http://www.epa.gov/pm/2012/finalria.pdf>. 785 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, NC: Office of Air Quality Planning and Standards, Health and Environmental Impacts Division, Air Benefit and Cost Group Research. (EPA document number EPA-452/R-08-003, March). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>. 786 U.S. Environmental Protection Agency (U.S. EPA). 2010. Section 3: Re-analysis of the Benefits of Attaining Alternative Ozone Standards to Incorporate Current Methods. Available at: <http://www.epa.gov/ttnecas1/regdata/RIAs/s3- supplemental_analysis-updated_benefits11-5.09.pdf>. 787 U.S. Environmental Protection Agency. 2013. Technical support document: Estimating the benefit per ton of reducing PM 2.5 precursors from 17 sectors. Research Triangle Park, NC: Office of Air and Radiation, Office of Air Quality Planning and Standards, January. Available at: <http://www.epa.gov/airquality/benmap/models/Source_Apportionmen t_BPT_TSD_1_31_13.pdf>.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1140 of 1275 reductions in this final rulemaking, and thus they may not reflect the local variability in population density, meteorology, exposure, baseline health incidence rates, or other local factors for any specific location. More information regarding the derivation of the benefit-per-ton estimates is

available in the RIA. PM benefit-per-ton values are generated using two concentration-response functions, Krewski et al. (2009) and Lepeule et al. (2012). These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. Even though we assume thatall fine particles have equivalent health effects, the benefitper-ton estimates vary between PM 2.5 precursors depending on the location and magnitude of their impact on PM 2.5 concentrations, which drive population exposure. It is important to note that the magnitude of the PM 2.5 and ozone co-benefits is largely driven by the concentration response functions for premature mortality and the value of a statistical life used to value reductions in premature mortality. For PM 2.5 , we use two key empirical studies, one based*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1141 of 1275 on the American Cancer Society cohort study 788 and one based on the extended Six Cities cohort study. 789 We present the PM 2.5 cobenefits results as a range based on benefit-per-ton estimates calculated using the concentration-response functions from these two epidemiology studies, but this range does not capture the full range of uncertainty inherent in the co-benefits estimates. In the RIA for this rule, which is available in the docket, we

also include PM 2.5 co-benefits estimates using benefit-per-ton estimates based on expert judgments of the effect of PM 2.5 on premature mortality (Roman et al., 2008) 790 as a characterization of uncertainty regarding the PM 2.5 -mortality relationship.

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

788 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution and Mortality. Health Effects Institute. (HEI Research Report number 140). Boston, MA: Health Effects Institute. 789 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. “Chronic Exposure to Fine Particles and Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” Environmental Health Perspective, 120(7), July, pp. 965-970. 790 Roman, H., et al. 2008. “Expert Judgment Assessment of the Mortality Impact of Changes in Ambient Fine Particulate Matter in the U.S.” Environmental Science & Technology , Vol. 42, No. 7, February, pp. 2268 – 2274.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1142 of 1275 function from Bell et al. (2004) 791 and the upper end based on a benefit-per-ton estimate using the function from Levy et al. (2005). 792 Similar to PM 2.5 , the range of ozone co-benefits does not capture the full range of inherent uncertainty. In this analysis, in estimating the benefits-per-ton for

PM 2.5 precursors, the EPA assumes that the health impact function for fine particles is without a threshold. This is based on the

conclusions of EPA’s Integrated Science Assessment for Particulate Matter, 793 which evaluated the substantial body of published scientific literature, reflecting thousands of epidemiology, toxicology, and clinical studies that documents

the association between elevated PM 2.5 concentrations and adverse health effects, including increased premature mortality. This assessment, which was twice reviewed by the EPA’s independent Science Advisory Board, concluded that the scientific literature

791 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 95 U.S. Urban Communities, 1987-2000.” Journal of the American Medical Association, 292(19), pp. 2372-8. 792 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone exposure and mortality: an empiric Bayes metaregression analysis.” Epidemiology . 16(4): p. 458-68. 793 U.S. Environmental Protection Agency. 2009. Integrated Science Assessment for Particulate Matter (Final Report)

. Research Triangle Park, NC: National Center for Environmental Assessment, RTP Division. (EPA document number EPA-600-R-08- 139F, December). Available at: http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1143 of 1275 consistently finds that a no-threshold model most adequately portrays the PM-mortality concentration-response relationship. In general, we are more confident in the magnitude of the

risks we estimate from simulated PM 2.5 concentrations that

coincide with the bulk of the observed PM concentrations in the epidemiological studies that are used to estimate the benefits. Likewise, we are less confident in the risk we estimate from

simulated PM 2.5 concentrations that fall below the bulk of the

observed data in these studies. For this analysis, policy-specific air quality data are not available, 794 and thus, we are unable to estimate the percentage of premature mortality associated with this specific rule. As a surrogate measure of mortality impacts, we provide the percentage of the population exposed above the lowest measured

PM 2.5 level (LML) in each of the studies from which we obtained concentration-response functions for PM 2.5 mortality, using the estimates of baseline projected PM 2.5 from the air quality modeling for the proposed guidelines used to calculate the benefit-per-ton estimates for the EGU sector. Using the Krewski et al. (2009) study, 88 percent of the population is exposed to

annual mean PM 2.5 levels at or above the LML of 5.8 micrograms

794 In addition, site-specific emission reductions will depend upon how states implement the guidelines.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1144 of 1275 per cubic meter (μg/m 3 ). Using the Lepeule et al. (2012) study, 46 percent of the population is exposed above the LML of 8 μg/m 3

. It is important to note that baseline exposure is only one parameter in the health impact function, along with baseline incidence rates, population, and change in air quality. 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 2.5 National Ambient Air Quality Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air quality input and monitoring data to conduct a complete benefits assessment. In addition, using a benefit-per-ton approach adds another important source of uncertainty to the benefits

estimates. The 2012 PM 2.5 NAAQS benefits analysis provides an indication of the sensitivity of our results to various*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1145 of 1275 assumptions.

We note that the monetized co-benefits estimates shown here do not include several important benefit categories, including exposure to SO 2 , NO X , and hazardous air pollutants (e.g., mercury and hydrogen chloride), as well as ecosystem effects and visibility impairment. Although we do not have sufficient information or modeling available to provide monetized estimates for this rule, we include a qualitative assessment of these unquantified benefits in the RIA for the final standards. For more information on the benefits analysis, please refer to the RIA for this rule, which is available in the rulemaking

docket. **XII. Statutory and Executive Order Reviews** Additional information about these Statutory and ExecutiveOrders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. A. Executive Order 12866: Regulatory Planning and Review, and Executive Order 13563: Improving Regulation and Regulatory

Review 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1146 of 1275 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 2 ) emission performance rates for two source categories of existing fossil fuel-fired EGUs, fossil fuel-fired electric utility steam generating units and stationary combustion turbines, and 2) guidelines for the development, submittal and implementation of state plans that implement the CO 2 emission performance rates. Actions taken to comply with the guidelines will also reduce the emissions of directly-emitted PM 2.5 , SO 2 and NO X . The benefits associated with

these PM 2.5 , SO 2 and NO X reductions are referred to as cobenefits, as these reductions are not the primary objective of

this rule.

The EPA has used the social cost of carbon estimates presented in the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866 (May 2013, Revised*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1147 of 1275 June 2015) (“current TSD”) to analyze CO 2 climate impacts of this rulemaking. We refer to these estimates, which were developed by the U.S. government, as “SC-CO 2 estimates.” The

SC-CO 2 is an estimate of the monetary value of impacts associated with a marginal change in CO 2 emissions in a given year. The four SC-CO 2 estimates are associated with different discount rates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent), and each increases over time. In this summary, the EPA provides the estimate of climate benefits

associated with the SC-CO 2 value deemed to be central in the current TSD: the model average at 3 percent discount rate. The EPA estimates that, in 2020, the final guidelines will yield monetized climate benefits (in 2011$) of approximately $[X] billion (3 percent model average). The air pollution health co-benefits in 2020 are estimated to be $[X] billion to $[X] billion (2011$) for a 3 percent discount rate and $[X] billion to $[X] billion (2011$) for a 7 percent discount rate. The annual, illustrativecompliance costs estimated by IPM and inclusive of demandside energy efficiency program and participant costs and MRR costs, are approximately $[X] billion (2011$) in 2020. The quantified net benefits (the difference between*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1148 of 1275 monetized benefits and compliance costs) in 2020 are estimated to range from $[X] billion to $[X] billion (2011$) 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 $[X] billion (3 percent model average). The air pollution health co-benefits in 2025 are estimated to be $[X] billion to $[X] billion (2011$) for a 3 percent discount rate and $[X] billion to $[X] billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance costs estimated by IPM and inclusive of demand side energy efficiency program and participant costs and MRR costs, are approximately $[X] billion (2011$) in 2025. The quantified net benefits (the difference between monetized benefits and compliance costs) in 2025 are estimated to range from $[X] billion to $[X] billion (2011$) 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 $[X] billion (3 percent model average). The air pollution health co-benefits in 2030 are estimated to be $[X] billion to $[X] billion (2011$) for a 3 percent discount rate and $[X] billion to $[X] billion (2011$) for a 7 percent discount rate. The annual, illustrative compliance costs estimated by IPM and*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1149 of 1275 inclusive of demand side energy efficiency program and participant costs and MRR costs, are approximately $[X] billion (2011$) in 2030. The quantified net benefits (the difference between monetized benefits and compliance costs) in 2030 are estimated to range from $[X] billion to $[X] billion (2011$) using a 3 percent discount rate (model average). **Table 14. Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Final Guidelines in 2020, 2025 and 2030**  **a [Billions of 2011$]** 

**Final Guidelines, 2020 3% Discount Rate 7% Discount rate**  **Climate benefits b**  $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X] **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment **Final Guidelines, 2025 3% Discount rate 7% Discount rate**  **Climate benefits b**  $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X]*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1150 of 1275 **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment **Final Guidelines, 2030 Climate benefits**  **b** $[X] **Air pollution health co-benefits**  **c** $[X] to $[X] $[X] to $[X] **Total Compliance Costs**  **d** $[X] $[X] **Net Monetized Benefits**  **e** $[X] to $[X] $[X] to $[X]

**Non-monetized Benefits**  Non-monetized climate benefits Reductions in exposure to ambient NO 2 and SO 2 Reductions in mercury deposition Ecosystem benefits associated with reductions in emissions of NO X , SO 2 , PM, and mercury Visibility impairment

a All are rounded to two significant figures, so figures may not sum. b The climate benefit estimate in this summary table reflects global impacts from CO 2 emission changes and does not account for changes in non-CO 2 GHG emissions. Also, different discount rates are applied to SC-CO 2 than to the other estimates because CO 2 emissions are long-lived and subsequent damages occur over many years. The benefit estimates in this table are based on the average SC-CO 2 estimated for a 3 percent discount rate, however we emphasize the importance and value of considering the full range of SC-CO 2 values. As shown in the RIA, climate benefits are also estimated using the other three SC-CO 2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95 th percentile at 3 percent). The SC-CO 2 estimates are yearspecific and increase over time.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1151 of 1275

c The air pollution health co-benefits reflect reduced exposure to PM 2.5 and ozone associated with emission reductions of directly emitted PM 2.5 , SO 2 and NO X . The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM 2.5 and ozone. These models assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type. d Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side energy efficiency program and participant costs.

e The estimates of net benefits in this summary table are calculated using the global SC-CO 2 at a 3 percent discount rate (model average). The RIA includes combined climate and health estimates based on additional discount rates. 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 2 emissions do not include important impacts like ocean acidification or potential tipping points in natural or managed ecosystems. Unquantified benefits also include climate benefits from reducing emissions of non-CO 2 greenhouse gases (e.g., nitrous oxide and methane) 795 and

795 Although CO 2 is the predominant greenhouse gas released by the power sector, electricity generating units also emit small amounts of nitrous oxide and methane. For more detail about power sector emissions, see RIA Chapter 2 and the U.S. Greenhouse Gas Reporting Program’s power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm l.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1152 of 1275 co-benefits from reducing direct exposure to SO 2 , NOx and hazardous air pollutants (e.g., mercury and hydrogen chloride), as well as from reducing ecosystem effects and visibility impairment.

B . Paperwork Reduction Act (PRA) 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, U.S. territories 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 2 emission performance goals that could be addressed through either tribal or federal plans. A tribe would have the opportunity under the TAR, but not the obligation, to apply to the EPA for TAS for purposes of a CAA section 111(d) plan and, if approved by the EPA, to establish a CAA section 111(d) plan for its area of Indian country. To date, no tribe*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1153 of 1275 has requested or obtained TAS eligibility for purposes of a CAA section 111(d) plan. For areas of Indian country with affected EGUs where a tribe has not applied for TAS and submitted any needed plan, if the EPA determines that a CAA section 111(d) plan is necessary or appropriate, the EPA would have the responsibility to establish the plans. Because tribes are not required to implement section 111(d) plans and because no tribe has yet sought TAS eligibility for this purpose, this action is not anticipated to impose any information collection burden on tribal governments over the 3-year period covered by this ICR. This rule does impose specific requirements on state and U.S. territory 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 2 emissions from existing sources in the utility power sector. These recordkeeping and reporting requirements 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.

The annual burden for this collection of information for the states (averaged over the first 3 years following*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1154 of 1275 promulgation) is estimated to be a range of 529,000 to 859,000 hours at a total annual labor cost of $37.4 to $60.8 million. The lower bound estimate reflects the assumption that some states already have energy efficiency and renewable energy programs in place. The higher bound estimate reflects the overly-conservative assumption that no states have energy efficiency and renewable energy programs in place.

The annual burden for this collection of information for the two affected U.S. territories, i.e., Puerto Rico and Guam, (averaged over the first 3 years following promulgation of this action) is estimated to be 23,700 to 38,200 hours at a total annual labor cost of $1.68 to $2.71 million. 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 54,901 hours at a total annual labor cost of $3.04 million. The total annual burden for the federal government associated with the territorial collection of information (averaged over the first 3 years following promulgation) is estimated to be 2,600 hours at a total annual labor cost of $145,000. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1155 of 1275 displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this

final rule.

C . Regulatory Flexibility Act (RFA) 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 and U.S. territories 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1156 of 1275 achieve the NAAQS through their state implementation plans. See American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have significant impacts upon small entities because NAAQS themselves impose no regulations upon small entities). 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.

D . Unfunded Mandates Reform Act (UMRA) 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1157 of 1275 not significantly or uniquely affect small governments. The emission guidelines do not impose any direct compliance requirements on EGUs located in states, U.S. territories 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 and U.S. territory governments that have affected EGUs. Specifically, states and U.S. territories are required to develop plans to implement the guidelines under CAA section 111(d) for affected EGUs. The burden for states and U.S. territories 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 and U.S. territory governments to which rule requirements apply are not considered small governments.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1158 of 1275 In light of the interest among governmental entities, the EPA conducted outreach with national organizations representing state and local elected officials and U.S. territory 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.

E . Executive Order 13132: Federalism 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1159 of 1275 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1160 of 1275 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1161 of 1275 of achieving interim CO 2 levels. They also identified the potential for electric system reliability issues and stranded assets due to the proposed timeframe for plan submittals and CO 2 emission reductions. In addition, states commented on state plan development and implementation topics, including state plan approaches, early actions, trading programs, interstate crediting for RE, and EPA guidance and outreach. Commenters identified overarching concerns regarding the stringency of the CO 2 goals and the timeframe for achieving reductions that encompassed the building blocks, the BSER, and associated timing for achievement of interim CO 2 levels. State commenters, in particular, identified changes to the stringency of the building blocks, concerns with the timeframe over which reductions must be achieved, and concerns with the approaches and measures used for the BSER. For the final rule, in response to stakeholder comments, the EPA has made refinements to the building blocks, the period of time over which measures are deployed, and the stringency of emission limitations that those measures can achieve in a practical and reasonable cost way. The

final BSER reflects those refinements. To many commenters, the proposal’s 2020 compliance date, together with the stringency of the interim CO 2 goal, bore significant reliability implications. In this final rule, the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1162 of 1275 agency is addressing those concerns via adjustments to the compliance timeframe (an 8-year interim period that begins in 2022) and to the approach for meeting interim CO 2 emission performance rates (a glide path separated into three steps, 2022-2024, 2025-2027, and 2028-2029). These adjustments provide more time for planning, consultation and decision making in the formulation of state plans and in EGUs’ choices of compliance strategies. The final rule also retains flexibilities presented in the proposal and offers additional opportunities, including opportunities for trading within and between states, and other multi-state compliance approaches that will further support electric system reliability. The EPA is also requiring states to consult with relevant ISOs/RTOs and/or planning/reliability authorities during plan development, and to document recommendations in their plans – and is providing the time for states to do so. Even with this foundation of flexibility in place, these final guidelines further provide states with the option of proposing amendments to approved plans in the event that unanticipated and significant reliability challenges arise. Commenters provided compelling information indicating that it will take longer than the agency initially anticipated to adjust investments and achieve interim CO 2 reductions. Recognizing this, as well as the urgent need for actions to*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1163 of 1275 reduce GHG emissions, the EPA is requiring states to frame an initial plan by August 31, 2016, and is allowing states two additional years to submit a final plan, if justified (to be submitted by August 31, 2018). 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 also expressed interest in the EPA ensuring that early actions to reduce CO 2 are rewarded. In this final rule, states with currently existing programs and policies, and states that put in place new programs and policies early, will be better positioned to achieve the CO 2 goals. Measures that a state takes prior to 2022, or programs already*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1164 of 1275 in place by 2022, that result in CO 2 emission reductions during the 2022-2029 period will contribute toward meeting both the

interim and final CO 2 emission performance rates. Thus, states with currently existing programs and policies, and states that put in place new programs and policies early, will be better positioned to achieve the goals. RE generating capacity and

demand-side EE measures that are installed after 2012 will be eligible for use in adjusting a CO 2 emission performance rate. 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 trackingsystems to support state administration of rate-based and massbased 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 theyachieve the required emission reductions from affected fossilfuel-fired EUGs. In addition, in response to concerns from states and power companies that the need for up-front interstate cooperation in developing mulit-state plans could inhibit the development of interstate programs that could lower cost, the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1165 of 1275 final rule provides additional options to allow individual EGUs to use creditable out-of-state reductions to achieve required CO 2 reductions, without the need for up-front interstate agreements. The EPA is committed to working with states to provide support for tracking of emissions and allowances or credits, to help implement multi-state trading or averaging approaches. 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, tribes and territories to ask technical and policy questions.The agency will host (or partner with appropriate groups to cohost) 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1166 of 1275 inform the training and other tools that will be of most use to the states, tribes, and territories 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 website. 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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1167 of 1275

F. Executive Order 13175: Consultation and Coordination with

Indian Tribal Governments This action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. 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 2 emissions from EGUs subject to section 111(d) of the CAA. The EPA also notes that none of the affected EGUs are owned or operated by tribal governments. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1168 of 1275 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 (e.g., over what time period, relationship to state and multi-state plans) and how tribes will participate in these planning activities.

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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1169 of 1275 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 2 emission standard based on the highest historical CO 2 emissions since 1996; the Navajo*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1170 of 1275 Nation requests that the EPA grant the Navajo Nation carbon credits and that the Navajo Nation retains ownership and control of such credits; building block 2 is not appropriate for the Navajo Nation because there are no NGCC plants located on the Navajo Nation; building block 3 is not appropriate for the Navajo Nation because the Navajo people already receive virtually all of their electricity from carbon-free sources (mostly hydroelectric power) and their use of electricity is negligible compared to the generation at the power plants; building block 4 is not appropriate for the Navajo Nation because of the inadequate access to electricity, and the goal should allow for an increase in energy consumption on the Navajo Nation; the supplemental proposal should consider the useful life of the power plants located on the Navajo Nation; and the supplemental proposal should clarify that RE projects located within the Navajo Nation that provide electricity outside the Navajo Nation should be counted toward meeting the relevant state’s RE goals under the Clean Power Plan. 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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1171 of 1275 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. 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.

G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1172 of 1275 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 2 is a potent greenhouse gas that contributes to climatechange and is emitted in significant quantities by fossil fuelfired power plants. The EPA believes that the CO 2 emission reductions resulting from implementation of these final guidelines, as well as substantial ozone and PM 2.5 emission reductions as a co-benefit, will further improve children’s

health.

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.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1173 of 1275 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. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use 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 [X] to [X] percent change in retail electricity prices on average across the contiguous U.S. in [20XX], and a [X] to [X] percent*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1174 of 1275 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/decrease by about [X] to [X] percent in [20XX]. 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. I. National Technology Transfer and Advancement Act This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations 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,*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1175 of 1275 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). 796 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

796 “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 66,496 (Dec. 15, 2009) (“Endangerment Finding”).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1176 of 1275 resources. See sections XII.F and XII.G, 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 (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*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1177 of 1275 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. 797 The new assessment literature provides more detailed findings

797 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United States: The Third National Climate Assessment. U.S. Global Change Research Program, 841 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 1132 pp. IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part B: Regional Aspects . Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 688 pp.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1178 of 1275 regarding these populations’ vulnerabilities and projected impacts they may experience. In addition, the most recent assessment reports provide new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These reports find that certain climate change related impacts—including heat waves, degraded air quality, and extreme weather events—have disproportionate effects on low-income populations and some communities of color, raising environmental justice concerns. Existing health disparities and other inequities in these communities increase their vulnerability to the health effects of climate change. In addition, assessment reports also findthat climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United

States. 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 by limiting GHG emissions through the*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1179 of 1275

establishment of CO 2 emission guidelines for existing affected

fossil fuel-fired EGUs. In addition to reducing CO 2 emissions, the guidelines finalized in this rulemaking would reduce other emissions from affected EGUs that reduce generation due to higher adoption of energy efficiency and renewable energy. These emission

reductions will include SO 2 and NOx, which form ambient PM 2.5 and ozone in the atmosphere, and hazardous air pollutants (HAP), such as mercury and hydrochloric acid. In the final rule revising the annual PM 2.5 NAAQS, 798 the EPA identified low-income populations as being a vulnerable population for experiencing adverse health effects related to PM exposures. Low-income populations have been generally found to have a higher prevalence of pre-existing diseases, limited access to medical treatment, and increased nutritional deficiencies, which can increase this population’s risk to PM-related and ozone-related

effects. 799 Therefore, in areas where this rulemaking reduces exposure to PM 2.5 , ozone, and methylmercury, low-income populations will also benefit from such emissions reductions.

798 “National Ambient Air Quality Standards for Particulate Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 799 U.S. Environmental Protection Agency (U.S. EPA). 2009. Integrated Science Assessment for Particulate Matter (Final Report) . EPA-600-R-08-139F. National Center for Environmental Assessment – RTP Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546 >.*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** Page 1180 of 1275 The RIA for this rulemaking, included in the docket for this rulemaking, provides additional information regarding the health and ecosystem effects associated with these emission reductions. Additionally, as outlined in the community considerations section IX of this preamble, the EPA has put a number of conditions in place to help ensure that this action will not have potential disproportionately high and adverse human health or environmental effects on all communities (low income, communities of color). As described in the community considerations section of this preamble the EPA also conducted a proximity analysis, which is available in the docket of this rulemaking and is discussed in section IX. K. Congressional Review Act (CRA) 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). **XIII. Statutory Authority** 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)).*** E.O. 12866 Review – Draft – Do Not Cite , Quote or Release During Review *** **Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric**  **Utility Generating Units** Page **1181** of **1275** List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Intergovernmental relations, Reporting and recordkeeping requirements.

___________________ Dated:

____________________ Gina McCarthy, Administrator.Page **1182** of **1275**Page **1183** of **1275**

For the reasons stated in the preamble, title 40, chapter I, part 60 of the Code of the Federal Regulations is amended as

follows:

**PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES** 1. The authority citation for Part 60 continues to read as

follows: **Authority:** 42 U.S.C. 7401 et seq. 2. Add subpart UUUU to read as follows: **Subpart UUUU: Emission Guidelines for Greenhouse Gas Emissions and Compliance Times for Electric Utility Generating Units** 

Sec. **Introduction** 60.5700 What is the purpose of this subpart? 60.5705 What pollutants are regulated by this subpart? 60.5710 Am I affected by this subpart? 60.5715 What is the review and approval process for my state plan? 60.5720 What if I do not submit a plan or my plan is not approvable? 60.5725 In lieu of a state plan submittal, are there other acceptable option(s) for a state to meet its section 111(d) obligations? 60.5730 Is there an approval process for a negative declaration letter? 60.5735 What authorities will not be delegated to state, local, or tribal agencies? 60.5736 Will the EPA impose any sanctions? **State and Multi-state Plan Requirements** 60.5740 What must I include in my plan? 60.5745 What must I include in my final plan submittal? 60.5750 Can I work with other states to develop a multi-state plan? 60.5755 Can I include existing requirements, programs, and measures in my plan? 60.5760 What are the timing requirements for submitting my plan?Page **1184** of **1275**

60.5765 What must I include in an initial plan submittal in lieu of a final plan submittal? 60.5770 What schedules, performance periods, and compliance periods must I include in my plan? 60.5775 What emission standards must I include in my plan? 60.5780 What state measures may I include in support of my plan? 60.5785 What is the procedure for revising my plan? 60.5790 What must I do to meet my plan obligations? **Emission Rate Credit Requirements** 60.5791 What Emission Rate Credits qualify for use in my state plan? 60.5792 How can an affected EGU use an ERC for demonstrating compliance? 60.5793 What is a qualified state ERC tracking system? 60.5795 What are the requirements for EM&V plans? 60.5796 What are the requirements for a post-project ERC verification assurance plan? 60.5797 What standards must the independent third party verifier meet? **Applicability of Plans to Affected EGUs** 60.5800 Does this subpart directly affect EGU owners and operators in my state? 60.5805 What affected EGUs must I address in my state plan? 60.5810 What affected EGUs are exempt from my state plan? 60.5815 What are the CO 2 emission performance rates for affected EGUs? 60.5820 What applicable monitoring, recordkeeping, and reporting requirements do I need to include in my state plan for affected EGUs? **Recordkeeping and Reporting Requirements** 60.5825 What are my state recordkeeping requirements? 60.5830 What are my state reporting requirements? 60.5835 How do I submit information required by these Emission Guidelines to the EPA?

**Definitions** 60.5840 What definitions apply to this subpart? Table 1 to Subpart UUUU of Part 60—CO 2 Emission Performance Rates (Pounds of CO 2 Per Net MWh) Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO 2 Emission Goals (Pounds of CO 2 Per Net MWh)Page **1185** of **1275**

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO 2 Emission Goals (Tons of CO 2 )

**Introduction § 60.5700 What is the purpose of this subpart?**  This subpart establishes emission guidelines and approval criteria for state or multi-state plans that establish emission standards limiting greenhouse gas 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 sections 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. **§ 60.5705 What pollutants are regulated by this subpart?** (a) The pollutants regulated by this subpart are greenhouse

gases. (b) The greenhouse gas regulated by this subpart is carbon dioxide (CO 2 ). **§ 60.5710 Am I affected by this subpart?**Page **1186** of **1275**

If you are the Governor of a state 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. You must submit a negative declaration letter in place of the state plan if there

are no affected EGUs for which construction commenced on or before January 8, 2014 in your state. **§ 60.5715 What is the review and approval process for my plan?** The EPA will review your plan according to § 60.27 except that under § 60.27(b) the Administrator will have twelve months after the date the final plan or plan revision (as allowed under § 60.5795) is submitted, to approve or disapprove such plan or revision or each portion thereof. If you submit an initial plan submittal under § 60.5765(a) in lieu of a final plan submittal the EPA will follow the procedure in § 60.5765(b). **§ 60.5720 What if I do not submit a plan or my plan is not approvable?**  (a) If you do not submit an approvable plan the EPA will develop a Federal plan for your state according to § 60.27 except that under § 60.27(d) the EPA will have one year to promulgate a Federal plan for your state from the date EPA finds you failed to submit a plan or EPA disapproves your plan. The Federal plan will implement the emission guidelines contained inPage **1187** of **1275**

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 prior to the beginning of the interim period on January 1, 2022. If a federal plan is in place during the interim period or final period and a state submits and EPA approves a plan, the federal plan will not be withdrawn until the end of the performance period that is at that time in place (e.g., at the end of an interim step so that the state plan goes into effect at the beginning of a new interim step). **§ 60.5725 In lieu of a state plan submittal, are there other acceptable option(s) for a state to meet its CAA section 111(d)**  **obligations?** 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). **§ 60.5730 Is there an approval process for a negative**

**declaration letter?** 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 F EDERAL R EGISTER . If, at a later date,Page **1188** of **1275**

an affected EGU for which construction commenced on or before January 8, 2014 is found in your state, you will have been found to have failed to submit a final plan as required, and a Federal plan implementing the emission guidelines contained in this subpart will apply to that affected EGU until you submit, and EPA approves, a final state plan. **§ 60.5735 What authorities will not be delegated to state, local, or tribal agencies?**  The authorities that will not be delegated to State, local, or tribal agencies are specified in paragraph (a) of this

section. (a) Approval of alternatives, not already approved by this subpart, to the CO 2 emissions performance rates in Table 1 to this subpart established under § 60.5815. (b) Approval of alternatives, not already approved by this subpart, to the CO 2 emissions goals in Tables 2 and 3 to this subpart established under § 60.5815. **§ 60.5736 Will the EPA impose any sanctions?** The EPA will not exercise any authority it may have to impose sanctions under the Clean Air Act, 42 U.S.C. §§ 7410(m), 7509, on states for failing to submit, implement, or enforce any requirements under this subpart. **State and Multi-state Plan Requirements § 60.5740 What must my state or multi state plan include?** Page **1189** of **1275**

(a) You must include the components described in paragraphs (a)(1) through (10) of this section in your plan submittal. These components of your plan submittal will be codified as part of the federally enforceable plan upon approval by EPA. The final plan submittal must meet the requirements and include the information required under § 60.5745. (1) Consistent with § 60.25(a), you must identify the affected EGUs covered by your plan and all affected EGUs in your state that meet the applicability criteria in § 60.5805. In addition you must include an inventory of CO 2 emissions from the affected EGUs during the most recent calendar year for which data is available prior to the submission of the plan. (2) You must include an identification of all emission standards for each affected EGU, compliance periods for each emission standard according to § 60.5770, and a demonstration that the emission standards are, when taken together, sufficiently protective to meet the applicable CO 2 emission performance rates described in § 60.5815. (i) If your plan includes only requirements of emission standards on your affected EGUs to meet either the CO 2 emission performance rates or CO 2 emission goals, you must include in your plan the requirement for corrective measures to be put in place if there is an exceedance of an interim step or final period CO 2 emission performance rate or CO 2 emission goal by 10 percent orPage **1190** of **1275**

greater, either on average or cumulatively as applicable. These corrective measures must ensure that the interim period and final period CO 2 emission performance rates or CO 2 emission goals are achieved by your affected EGUs. (ii) If your plan includes state measures, in addition to or in lieu of emission standards, then the final state plan must include the information in paragraph (a)(3) and the submittal must include the information listed in § 60.5745(a)(6). (3) If your plan includes state measures, you must submit a federally enforceable backstop that identifies emission standards for affected EGUs that will be put into place if there is an exceedance of 10 percent or greater of any interim step goal or final goal period. The emission standards in the backstop must be able to meet either the CO 2 emission performance

rates or CO 2 emission goal required by your plan for both the interim period and final periods, as well as any shortfall identified from the prior compliance period. The backstop must also address the following: (i) You must include a trigger for the backstop to go into effect upon either a failure to meet a programmatic milestone or an exceedance of 10 percent or greater of any interim step goal or final goal period. You may include in your plan any additional triggers so long as they do not affect the stringency of the two triggers required under this paragraph.Page **1191** of **1275**

(ii) 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) Identification of applicable monitoring, reporting, and recordkeeping requirements for each affected EGU. These requirements must be consistent with or no less stringent than the requirements specified in **§** 60.5820 **.** (5) Description of the process, contents, and schedule for state reporting to the EPA about plan implementation and progress including information required under § 60.5830. (6) A requirement for a report to be submitted by July 1, 2021, that demonstrates that the state has met the programmatic 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 plan as of January 1,

2022. (b) You must follow the requirements of subpart B of this part (Adoption and Submittal of state plans for Designated Facilities) and demonstrate that they were met in your state plan. However, the provisions of § 60.24(f) shall not apply. **§ 60.5745 What must I include in my final plan submittal?** (a) In addition to the components of the plan listed in § 60.5740 a final plan submittal to the EPA must include thePage **1192** of **1275**

information in paragraphs (a)(1) through (10) of this section.

This information must be submitted to the EPA 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 approachand the geographic scope of the plan (i.e., state or multistate, geographic boundaries related to the plan elements), including, if applicable, identification of multi-state plan participants. (2) You must identify CO 2 emission performance rates or equivalent statewide emission goals that your affected EGUs will achieve through the implementation of your plan. If the geography scope of your plan is a single-state then you must

include CO 2 emission performance rates or emission goals according to § 60.5815. If your plan includes multiple states and you elect to set CO 2 emission performance goals, you must

include CO 2 emission goals calculated according to § 60.5750. (i) You must specify in the plan the CO 2 emission performance rates or emission goals that affected EGUs will meet for the interim period, interim steps 1, 2 and 3 and final period described in § 60.5770. (3) You must include a demonstration that the affected EGUs covered by the plan are projected to achieve the CO 2 emission performance rates or CO 2 emission goals described in § 60.5815.Page **1193** of **1275**

(4) You must include a demonstration that each affected EGU’s emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable according to section

60.5775. (5) If your plan includes only emission standards on your

affected EGUs to meet either the CO 2 emission performance rates

or CO 2 emision goals you must include in your plan submittal the information in paragraphs (a)(5)(i) through (iii) as applicable. (i) If the emission standards in your plan applies separate

rate-based CO 2 emission standards for affected EGUs (in lbs

CO 2 /MWh) that are equal to or lower than the CO 2 emission performance rates listed in table 1 then no additional demonstration is required beyond inclusion of the emission standards in the plan. Under this approach, compliance by

affected EGUs with the emission standards will ensure that the

CO 2 emission performance rates or the state rate-based CO 2 emission goal is achieved. (ii) If a plan applies rate-based emission standards to

individual affected EGUs at a lb CO 2 /MWh rate that differs from

the CO 2 emission performance rates in table 1 of this subpart or

the state’s rate-based CO 2 emission goal in table 2 of this subpart, then a further demonstration is required that the application of the CO 2 emission standards will achieve the CO 2 emission performance rates or state rate-based CO 2 goal. You mustPage **1194** of **1275**

demonstrate through a projection that the weighted average CO 2 emission rate of affected EGUs, when weighted by generation (in MWh), will be equal to or less than the CO 2 emission performance

rates or the rate-based CO 2 emission goal. This projection must address both the interim period (including interim step periods 1-3, for 2022-2024, 2025-2027, and 2028-2029), and the final period (2030-2031, and subsequent two-year periods). The projection in the plan submittal must include the following: (A) A summary of each affected EGU’s anticipated future operation characteristics, including annual generation, CO 2 emissions, capacity and capacity factors; (B) Planned affected EGU retirements; (C) Anticipated use of ERCs to adjust the reported CO2 emission rate of affected EGUs, including but not limited to, anticipated use (in MWh) by technology-type (e.g., wind, solar, demand-side EE), the physical location of the resources providing ERCs, and any other relevant information (e.g., power purchase agreements (PPAs) and other long-term power contracts); and an explanation, with calculation, of how these measures are being used in the projection to adjust the CO 2 emission rate of affected EGUs; (D) Expected electricity demand growth at the state or regional level, including the source and basis for these estimates;Page **1195** of **1275**

(E) Expected fuel switching at affected EGUs; (F) Heat rate improvements at affected EGUs; and (G) Any other applicable assumptions used in the projection. (iii) If a plan applies mass-based emission standards to individual affected EGUs you must include a demonstration that your mass-based emission program will be designed such that compliance by affected EGUs would achieve the state mass-based

CO 2 emission goals. This demonstration includes emission budgets for affected EGUs during the interim and final plan performance periods that are equal to or lower than the applicable state

mass-based CO 2 goals specified in table 3 of this subpart. Compliance periods for affected EGUs must aligned with each of the interim steps and final plan periods. (6) If your plan includes state measures, in addition to or in lieu of the emission standards required by paragraph (a)(2) of § 60.5740, the final state plan submittal must include the information under paragraphs (a)(6)(i) through (vi): (i) You must include a description of all the state measures the state will rely upon to achieve the applicable CO 2 emission performance rates or CO 2 emission goal, the applicable state laws or regulations related to such measures, and identification of parties or entities implementing such state

measures.Page **1196** of **1275**

(ii) You must include the schedule and milestones for the implementation of the state measures. If the state measures inyour plan submittal rely upon renewable energy (RE) or demandside energy efficiency (EE) programs and projects you must also demonstrate the minimum emission, monitoring and verification (EM&V) requirements listed under § 60.5795 that apply to those programs and projects. (iii) You must demonstrate that the federally enforceable emission standards for affected EGUs, if included, and state measures, are sufficient to attain the CO 2 emission performance

rates or CO 2 emission goal for the interim period of 2022-2029 and the final period of 2030 and beyond. This includes the interim period of 2022-2029, including interim step 1 2022-2024 period, interim step 2 2025-2027 period, and interim step 3 2028-2029 period (or alternative CO 2 emission performance step levels adopted by the state, provided they result in achievement

of the CO 2 emission performance rates or state CO 2 emission goal during the 2022-2029 interim period), as well as the final period of 2030 and beyond. Your demonstration must use technically sound quantification methods that are reliable and replicable. The demonstration must be supported by the methods and measurement procedures by which the federally enforceable CO 2 emission standards for affected EGUs are reliably measured, ifPage **1197** of **1275**

these standards are incorporated into the state measures state plan. (iv) You must include a CO 2 performance projection of your

state measure that shows how the measures will achieve the

future CO 2 performance at affected EGUs. Elements of this projection must include the following for the interim and final periods: (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 explanation of the tools and emission quantification approaches used in the projection; and (D) Underlying emission quantification assumptions. (v) If the state measures in your plan submittal are designed to meet either a CO 2 emission performance rate or ratebased CO 2 emission goal, MWh from state measures may be used to adjust the denominator of the CO 2 emission rate of affected EGUs when demonstrating achievement of the CO 2 emission performance

rates or the rate-based CO 2 emission goal. In this case your plan submittal must include the following information, at a minimum, to demonstrate state measures will require affected EGUs to meet

the CO 2 emission performance rates or the rate-based CO 2 emission goal:Page **1198** of **1275**

(A) A summary of each affected EGU’s anticipated future operation characteristics, including annual generation, CO 2 emissions, capacity and capacity factors; (B) Planned retirements; (C) A detailed description of the zero CO 2 emitting demandside energy efficiency (EE) savings and renewable energy (RE) generation (and any other qualifying MWh) from state measures that will be available for use in adjusting the reported CO 2 emission rates of affected EGUs, including, but not limited to, the amount of generation or savings by technology-type (e.g., wind, solar, EE), the physical location of the measures or generation, and any other relevant information (e.g., power purchase agreements (PPAs) and other long-term power contracts); and an explanation, with calculation, of how these measures are being used in the projection to adjust the CO 2 emission rate of affected EGUs; (D) Expected electricity demand growth at the state or regional level, including the source and basis for these estimates; (E) Expected fuel switching at affected EGUs; (F) Heat rate improvements at affected EGUs; and (G) Any other applicable assumptions used in the projection.Page **1199** of **1275**

(vi) If the state measures in your plan submittal are designed to meet mass-based CO 2 emission goals, a state must demonstrate that the combined state-enforceable measures, along with any federally enforceable CO 2 emission standards for affected EGUs, if included, will achieve the state mass-based CO 2 emission goal. You must demonstrate and document how the combined state measures are impacting CO 2 emissions at affected

EGUs so that the sum of emissions at all affected EGUs will be

lower than or achieve the state’s CO 2 emission goal for each of the interim steps and final period. (7) Your plan must demonstrate any regional information considered in developing the assumptions. Multi-state plans or plans sharing common elements should use regional assumptions ordemonstrate reconciliation of any inconsistencies between statelevel assumptions. (8) Your plan submittal must include a demonstration that the reliability of the electrical grid has been thoroughly

considered. (9) 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. (10) Supporting material for your plan including:Page **1200** of **1275**

(i) Materials demonstrating the state's legal authority to carry out each component of its plan, including emissions standards or state measures; (ii) Materials supporting that the CO 2 emission performance

rates or CO 2 emission goals will be achieved by affected EGUs under the plan, according to paragraph (a)(3) of this section; (iii) Materials supporting any calculations for CO 2 emission goals calculated according to § 60.5815, if applicable; and (iv) Materials necessary to support evaluation of the plan by the EPA. (v) Materials supporting each hearing held including the 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 40 CFR 60.23(f) (b) You must submit your final plan according to §

60.5835. **§ 60.5750 Can I work with other states to develop a multi-state plan?**  A multi-state plan may be submitted on behalf of multiple states, provided it is formally signed by the Governor or the Governor’s designee 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 eachPage **1201** of **1275**

participating state. A multi-state plan must include all therequired elements for a plan specified in § 60.5740(a). A multistate 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 states participating in the multi-state plan will

meet the CO 2 emission performance rates listed in table 1 or an equivalent CO 2 emission goal according to paragraphs (a)(1) or (2) of this section. (1) For states electing to demonstrate performance with a

CO 2 emission rate-based goal, the CO 2 emission goals identified in the plan according to § 60.5815 will be a weighted (by net energy output) average lb CO 2 /MWh emission rate to be achieved by all affected EGUs in the multi-state area during the plan periods; or (2) For states electing to demonstrate performance with a

CO 2 emission mass-based goal, the CO 2 emission goals identified in the multi-state plan according to § 60.5815 will be total CO 2 emissions by all affected EGUs in the multi-state area during the plan periods. (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 participatingPage **1202** of **1275**

states. The joint submittal must be signed by authorizedofficials for each of the states participating in the multistate plan. 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. (2) States participating in a multi-state plan may submit a single plan submittal, signed by authorized officials from each participating state, that addresses common plan elements and each individual participating states must, in addition, provide individual plan submittals that provide 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 allparticipating states, and also must address individual statespecific aspects of the multi-state plan. Each individual state plan submittal must address all required plan components in §

60.5740. **§ 60.5755 Can I include existing requirements, programs, and measures in my plan?** Page **1203** of **1275**

(a) Yes, existing state programs, requirements, and measures, meeting the requirements in paragraph (b) of this section may qualify for use in projecting and demonstrating that a plan achieves the CO 2 emission performance rates or emission goals specified in a plan, according to § 60.5815. (b) Emission impacts of existing programs, requirements, and measures that occur during a plan performance period must meet the following requirements to qualify for use in projecting and demonstrating that a plan achieves the CO 2 emission performance rates or emission goals specified in a plan, according to § 60.5815: (1) Actions taken pursuant to an existing state program, requirement, or measure, such as compliance with a regulatory obligation or initiation of an action related to a program or measure, must occur after December 31, 2012; and (2) The existing state program, requirement, or measure, and any related actions taken pursuant to such program, requirement, or measure, meet the applicable requirements pursuant to § 60.5740(a), § 60.5780 and § 60.5785. **§ 60.5760 What are the timing requirements for submitting my plan?**  (a) You must submit a final plan with the information required under § 60.5745 by August 31, 2016 unless you are submitting an initial plan submittal, allowed under § 60.5765,Page **1204** of **1275**

in lieu of a final state plan submittal according to paragraphs (b) of this section. (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 plan submittal by August 31, 2016 to receive an extension to submit your final state plan submittal by August 31, 2018. (c) You must submit all information required under paragraphs (a) and (b) of this section according to the electronic reporting requirements in § 60.5835. **§ 60.5765 What must I include in an initial plan submittal if requesting an extension for a final state plan submittal?**  (a) You must include the following required elements in an initial plan submittal if requesting an extension for a final plan submittal: (1) A description of the plan approach and progress made to date in developing each of the plan elements in § 60.5740; (2) An initial projection of the level of emission performance that will be achieved under the final plan; (3) A commitment by the state or states to maintain existing state measures that limit or avoid CO 2 emissions from affected EGUs (e.g., renewable energy standards, unit-specific limits on operation or fuel utilization);Page **1205** of **1275**

(4) Justification of why additional time is needed to submit a final plan (e.g., 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); (5) A comprehensive roadmap describing in detail the action you intend to take to submit all required elements of a final plan submittal as specified in § 60.5740 by no later than August 31, 2017, including process, analytical methods and schedule (including milestones) specifying when all necessary plan components will be complete (e.g., projection of emission performance; implementing legislation, regulations and agreements; necessary approvals); (6) Identification of existing and future programs, requirements, and measures the state or states intend to include in the plan and supporting materials as appropriate; (7) If a multi-state plan is being developed, an executed agreement(s) with other states (e.g., memorandum ofunderstanding) participating in the development of the multistate plan; (8) A description of all steps the state or states have already taken in furtherance of actions needed to finalize a final plan submittal; andPage **1206** of **1275**

(10) Evidence of an opportunity for public comment and a response to any significant comments received on issues relating to the approvability of the initial plan. (b) You must submit an initial plan 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 § 60.5830. If a state submits an initial plan 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 plan submittal that the EPA finds the initial plan submittal does not meet the requirements listed in paragraph (a) of this section. (c) If an extension for submission of a final plan has been granted, you must submit a progress report by August 31, 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 plan submittal and a list of which components are not complete.(2) A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), including draft or proposed legislation and/or regulations.Page **1207** of **1275**

(3) 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. (d) If you do not submit an acceptable update by August 31, 2017, you will have failed to meet the conditions for the 2-year extension and EPA will develop a federal plan unless you submit a final plan during this time. **§ 60.5770 What schedules, performance periods, and compliance periods must I include in my state plan?**  (a) You must meet the emission reduction requirements for the affected EGUs for the interim period, interim steps 1, 2 and 3 and final period according to paragraph (b) of this section. You must also include in your plan schedules of compliance for each affected EGU regulated under the plan according to paragraphs (c) and (d) of this section. (b) Your plan must achieve each state emission performance rate required under § 60.5815 over its applicable time periods according to paragraphs (b)(1) through (3) of this section: (1) The interim period must cover the eight calendar years 2022-2029 starting January 1, 2022 and ending December 31, 2029. (2) The interim steps are increments of plan performance within the interim period. Interim step 1 must cover the three calendar years 2022-2024, interim step 2 must cover the threePage **1208** of **1275**

calendar years 2025-2027 and interim step 3 must cover the two calendar years 2028-2029. (3) The final period must cover the years 2030 and thereafter and with increments of plan performance for every two calendar years (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). (c) If your state adopts emission standards for affected EGUs regulated under the plan, the emission standards for affected EGUs must include the following compliance periods for

the emission standards: (1) For the interim period, affected EGUs must have emission standards that have schedules of compliance for each interim step 1, 2 and 3 for the calendar years January 1, 2022 to December 31, 2024, January 1, 2025 to December 31, 2027, and January 1, 2028 to December 31, 2029, respectively. (2) For the final period, EGUs must have emission standards that have schedules of compliance for each two calendar years starting in 2030 (i.e., January 1, 2030 to December 31, 2031, January 1, 2032 to December 31, 2033, January 1, 2034 to December 31, 2035, etc.). (3) Schedules of compliance for interim step 1, 2, 3 and the final period may take forms shorter than the applicable 3 or 2 calendar years specified in paragraphs (1) or (2) as long as those schedules of compliance collectively end on the same schedule as the interim steps and final periods.Page **1209** of **1275**

(d) If your plan includes state measures in lieu of or in addition to emission standards for affected EGUs regulated under the plan then the state measures must include the compliance periods for affected EGUs listed in (c)(1) through (3). **§ 60.5775 What emission standards must I include in my plan?** (a) Emission standard(s) for affected EGUs under your state plan must be quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected EGU. The plan shall 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, orPage **1210** of **1275**

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 is 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 and the state maintain the ability to enforce violations and secure appropriate corrective actions pursuant to sections 113(a) through (h) of the Act, 42 U.S.C. §§ 7413(a)-(h), and states and other third parties maintain the ability to enforce against violations and secure appropriate corrective actions pursuant to section 304 of the Act, 42 U.S.C.

§ 7604. (g) Your plan must ensure that 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 itsPage **1211** of **1275**

emission standard by July 1 following the relevant compliance period, 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. (i) In addition to any other recourse provided in Sections 113 (a) – (h) or Section 304 of the Clean Air Act, 42 U.S.C. §§ 7413(a)-(h), 7604, for each compliance period in which an affected EGU does not meet its CO2 emission standard, it will be required to retire 2 times the number of ERCs that would have brought it into compliance with its CO 2 emission standard, and it must retire them by the end of the compliance period immediately following the compliance period in which it did not meet its CO2

emission standard. (ii) Failure to retire these replacement ERCs is an additional violation that may be subject to federal enforcement. (h) If an affected EGU obtained sufficient facially valid ERCs to meet its emission standard as specified in (a), but those ERCs were found to be invalid, it may be subject to federal enforcement as specified in (g). (i) For purposes of determining the number of days of violation for calculation of civil penalties and other relief,

if an affected EGU does not meet its emission standard for aPage **1212** of **1275**

compliance period, each day in the compliance period constitutes a day in violation. For a two calendar year compliance period, the number of days in violation is 730 or 731 days. For a three calendar year compliance period, the number of days in violation is 1,095 or 1,096 days **§ 60.5780 What state measures may I include in support of my plan?**  (a) You may include state measures in support of your plan that are not emission standard(s) on affected EGU’s, provided those state measures meet the following requirements:(1) Each state measure is quantifiable, verifiable, nonduplicative, permanent, and enforceable with respect to each affected entity (which may be, but is not limited to, an affected EGU), and your plan supporting materials includes the methods by which each state measure meets each of the following requirements in paragraphs (i) through (v) of this subpart. (i) A state measure is quantifiable with respect to an affected entity if it can be reliably measured, in a manner that can be replicated. (ii) 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.Page **1213** of **1275**

(iii) 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 multi-state plan. (iv) 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 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 CO 2 emission performance

rates. (v) A state measure is enforceable against an affected entity if: (A) A technically accurate limitation or requirement and the time period for the limitation or requirement is specified; (B) Compliance requirements are clearly defined; (C) The affected entities responsible for compliance and liable for violations can be identified; (D) Each compliance activity or measure is enforceable as a practical matter; and (E) The state maintains the ability to enforce violations and secure appropriate corrective actions.Page **1214** of **1275**

(b) If you include a rate-based ERC trading program as part of your state measures, the documentation supporting your submittal must show that your state regulations include all of the same requirements as those specified in § 60.5791 through § 60.5797 and any other applicable requirements that a state would need to include in a rate-based ERC trading program approvable as part of a plan. **§ 60.5785 What is the procedure for revising my plan?** (a) Plans can only be revised 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 2 emission performance rates in § 60.5815. If one (or more) of the elements of the plan set in § 60.5740 require revision with respect to achieving the CO 2 emission performance rates in § 60.5815, a request must be submitted to the Administrator indicating the proposed revisions to the plan to ensure the CO 2 emission performance rates are met. In addition, the following provisions in (b) through (d) may apply. (b) You may submit revisions to a plan to adjust CO 2 emission goals under the following instances:Page **1215** of **1275**

(1) Addressing data corrections to state goal, which result in no more than a 2 percent change in the state goal; and (2) Addressing EGUs that become subject to subpart TTTT of this Part and are no longer considered affected EGUs for incorporation in a plan. (c) If your state submits a notification according to section § 60.5830(d) indicating an exceedance of 10 percent or greater of a CO 2 emission performance rate or CO 2 emission goal you must revise your state plan to include corrective measures to be implemented. The corrective measures must ensure future

achievement of the CO 2 emission performance rates or state CO 2 emission goal and achieve additional emission reductions to offset any emission performance deficiency that occurred during an exceeded interim step(s) or final period(s). The state must submit the revised plan to the EPA within 24 months after submitting the state report required in section § 60.5830(a) indicating the exceedance in lieu of the requirements of § 60.28 (a). (d) You may apply to have a short–term modification to a plan to respond to any instances that can be characterized as a reliability safety valve issue without needing to go through the full state plan revision process if the state provides proper notification to the EPA. The short term modification, if approved allows modification to emission standards for anPage **1216** of **1275**

affected EGU or EGUs so that for a maximum of 90 days, the EGU or EGUs may operate at an emission standard that is above the emission standard specified in the relevant plan. However, you must ensure in your submittal that the CO 2 emission performance

rates or the state CO 2 emission goal will still be achieved. (1) To request this short-term modification you must submit a notification to the EPA including: (i) A full description of the reliability concern and why the affected EGU (or EGUs) needs to operate under modified emission standards from those originally required in the plan; (ii) A description of how it is coordinating or will coordinate, with relevant planning authorities to alleviate the problem in an expedited manner; (iii) A written concurrence from the relevant planning authority supporting the temporary modification request or an explanation of why this kind of concurrence cannot be provided;

and (iv) Additional information with respect to whether or not the relevant planning authority has conducted a system-wide or other analysis of the reliability safety valve concern. (2) If the short term modification is approved then at the end of modification period, of 90 days or less, you must submit a notification to the EPA including: (i) Whether the reliability concern has been addressed;Page **1217** of **1275**

(ii) Whether you are requiring the affected EGU, or EGUs, to meet the original emissions standards in the state plan approved prior to the short-term modification going forward; (iii) How the CO2 emission performance rates or state CO2 emission goals will be met going forward and enumerate how it will make up for any emission reductions that were lost during the safety valve period; and (iv) If there still is a serious, ongoing reliability issue, then you must provide to the EPA a notice that you will be submitting a state plan revision according to paragraph (a)

of this section. **§ 60.5790 What must I do to meet my plan obligations?** (a) To meet your plan obligations by requiring either emission standards or state specific measures on your affected EGUs as specified in § 60.5740, you must demonstrate your affected EGUs are complying with their CO 2 emission performance rates or state specific CO 2 emission goals using the procedures in paragraphs (b), (c) and (d) of this section. If your plan requires the use of Emission Rate Credits (ERCs) for your affected EGUs to comply with their emission standards you must follow the requirements under paragraph (e). (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 thePage **1218** of **1275**

emission budget and related compliance requirements and mechanisms. These requirements must include: (1) CO 2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs; (2) Provisions for state allocation of allowances; (3) Provisions for tracking of allowances, from issuance through submission for compliance; and (4) The process for affected EGUs to demonstrate compliance (allowance “true-up” with reported CO2 emissions). (c) If you submit a plan that sets rate-based emission standards on your affected EGUs, to meet the requirements of § 60.5775, you shall require the affected EGUs covered by your plan to demonstrate compliance with its emission standard by factoring stack emissions and any qualifying ERCs into the following equations:

ܱܥ ଶ ൌ ݁ݐܽݎ	݊݋݅ݏݏ݁݉݅	݈݅ܽ݊ܿ݁݌݉݋ܿ ∑ ܯ ைଶ஼ ∑ ܹ݄ܯ ௣௢ ൅ ∑ ܹ݄ܯ ஼ாோ Where:

M CO2 = Measured CO 2 mass in units or pounds (lbs) summed over the compliance period for an affected EGU.

MWh op = Total source operation over the compliance period

for an affected EGU in units of MWh.

MWh ERC = ERC replacement generation for an affected EGU in

units of MWh.Page **1219** of **1275**

(d) If you submit a plan that sets rate-based emission standards and/or state specific measures on affected EGUs, to meet the requirements of § 60.5780, you shall require the affected EGUs covered by your plan to demonstrate compliance with its emission standard by factoring stack emissions and any qualifying Emission Reduction Credits (ERCs) into the equation listed in paragraph (c) of this section. (e) If you want an affected EGU subject to a rate-based emission standard (whether under an emission standard plan or as a part of the federally enforceable backstop in a state measures plan) to be able to use ERCs issued pursuant to your state measures to demonstrate compliance with its emission standard, to meet the requirements of § 60.5775, such ERCs must meet the requirements of § 60.5791 and § 60.5792. (f) States may submit a rate-based emission trading program with alternative components other than those described in § 60.5791 through § 60.5797 so long as the submittal satisfactorily demonstrates that the trading system and its alternative components are at least as stringent in all respects as those in § 60.5791 through § 60.5797. **Emission Rate Credit Requirements §60.5791 What Emission Rate Credits qualify for use in my state**  **plan?** (a) An ERC qualifies for the compliance demonstrationPage **1220** of **1275**

specified in §60.5785, and will be considered a valid qualifying ERC for the purpose of inclusion in a plan if it meets each of the following requirements: (1) It was issued based on energy generated or saved after January 1, 2022, from a qualifying ERC generating resource, by a state (or it’s state agent) with a qualified state ERC tracking system that meets the requirements of section 60.5792 and was approved by EPA in its plan; (2) It represents one MWh of energy generated or saved (each one MWh can only generate one ERC) from a qualifying ERC generating resource with zero associated CO 2 emissions (in the case of a qualifying ERC generating resource that emits a fractional MWh, aggregation to one MWh is required); (3) It has a unique serial number, where the serial number must begin with the two digit postal abbreviation of the state in which it was issued and be followed by an identification number issued by the state that identifies the location where the ERC was generated; (4) Its CO 2 emissions have not been transferred outside the

ERC; (5) It is and has been owned by only one person at one time; (6) It exists in only one account on a qualified state or EPA ERC tracking system; andPage **1221** of **1275**

(7) It was issued to a qualifying ERC generating resource that is located in a state whose affected EGUs are subject to rate-based emission standards or state measures pursuant to this regulation, unless the qualifying ERC generating resource is

located in a state with mass-based emission standards and the qualifying ERC generating resource has a power purchase agreement or contract for delivery of its generation into a state whose affected EGUs are subject to rate-based emission standards or state measures pursuant to this regulation. (b) Nothing in paragraph (a) of this section precludes an ERC from representing other environmental attributes, in

addition to its CO2 emission. (c) An ERC may be transferred bundled together with an underlying MWh of energy generated that it was based on or unbundled from it; however, only the ERC and not the underlying MWh of energy (whether bundled or unbundled) may be used for purpose of compliance with this regulation. (d) Any ERC that does not meet the requirements of this subpart cannot be used in the compliance demonstration required under section 60.5785 and is consequently an invalid ERC. **§ 60.5792 How can an affected EGU use an ERC for demonstrating compliance?**  (a) An ERC may be used in the compliance demonstration specified in § 60.5785 if:Page **1222** of **1275**

(1) It meets the requirements of § 60.5791 and this subpart; (2) It is surrendered only once by one affected EGU for purpose of compliance with this regulation in accordance with § 60.5793 (e); and (3) It is retired through a qualified state ERC tracking system that meets the requirements of § 60.5793, or through an EPA ERC tracking system. (b) An ERC may not be used in the compliance demonstration specified in § 60.5785 if any state has used that same ERC for purposes of demonstrating achievement of its state measures. (c) An affected EGU subject to an emission standard is prohibited from including ERCs that were generated from an activity, project or program in a state with affected EGUs subject to mass-based emission standards in its compliance demonstration required under § 60.5785, unless the requirements of § 60.5791(a)(7) are met. (d) Provided it only surrenders an ERC for retirement once, an affected EGU can retire the same ERC for compliance with this regulation and for compliance with other state and local requirements. An affected EGU cannot retire an ERC for its compliance with this regulation and transfer the ERC to another entity for compliance with a state or local requirement. **§ 60.5793 What is a qualified state ERC tracking system?**Page **1223** of **1275**

(a) A qualified state ERC tracking system must meet each of the requirements of paragraphs (b) through (n). (b) Basic Functions. A qualified state ERC tracking system is a system that electronically issues and/or accepts, tracks, transfers, and retires ERCs that meet the requirements of § 60.5791 and the remainder of this subpart. (c) Account structure. A qualified state ERC tracking system must include accounts for the types of uses listed in paragraphs (c)(1) through (3) of this section. (1) A general use account, which affected EGUs, qualifying ERC generating resources, and any other person may establish an account for holding and trading ERCs. (2) A surrender account, into which affected EGUs will place ERCs intended for use in compliance with an emission standard or state measure, and from which the ERCs will be retired for purpose of compliance with a plan. (3) A retirement account, into which the qualified state ERC tracking system will place all ERCs retired for purpose of compliance with this regulation. (d) ERC eligibility, generation and issuance. A qualified state ERC tracking system must meet the requirements in paragraphs (d)(1) through (6) for ERC issuance. (1) Registration. A qualifying ERC generating resource registers with the qualified state ERC tracking system pursuantPage **1224** of **1275**

to the requirements of paragraph (l) of this section, and an independent third party verifier registers with the qualified ERC tracking system pursuant to the requirements of paragraph (m) of this section. (2) Eligibility approval. A qualifying ERC generating resource submits to the qualified ERC tracking system an EM&V eligibility application that is consistent with EPA’s minimum criteria set forth in § 60.5795. An independent third party verifier that meets the requirements of § 60.5797 reviews the EM&V eligibility application and certifies, in a verification assurance plan that meets the requirements of §60.5796 that the particular activity, project, or program covered by the EM&V eligibility application that is consistent with EPA’s minimum criteria set forth in § 60.5795. The state or its state agent approves the eligibility of the particular activity, project, or program covered by the EM&V eligibility application to generate ERCs for use in compliance with this regulation. (3) Registration and eligibility approval may occur at the same time as submission of the first post-project EM&V report or

in advance of it. (4) ERC issuance. (i) Following implementation of the particular activity, project or program specified in paragraph (d)(1) of this section, an affected EGU or qualifying ERC generating resourcePage **1225** of **1275**

submits to the qualified state ERC tracking system a postproject EM&V report that is consistent with EPA’s minimum criteria set forth in § 60.5795 and reports the MWh of energy generation or energy savings attributable to the activity, project or program over the specific period and as covered by the EM&V plan. Such EM&V plans must be submitted no less frequently than annually for a particular activity, project or

program. (ii) An independent third party verifier that meets the requirements of § 60.5797 reviews the post-project EM&V report and provides a verification assurance plan that meets the requirements of § 60.5796. Such verification assurance plans shall be submitted on the same periods as the EM&V reports that they verify, which according to paragraph (d)(4)(i) must be no less frequently than annually for a particular activity, project

or program. (iii) The state or its state agent reviews the post-project EM&V report and verification assurance plan and any other credible evidence, ensures that the EM&V report and verification assurance plan meet the requirements of § 60.5795 and § 60.5796, determines the number of ERCs that were generated (if any) during the specific period covered by the EM&V plan, and issues a corresponding amount of ERCs into the generation account of the affected EGU or qualifying ERC generating resource.Page **1226** of **1275**

(5) Frequency of ERC issuance. A qualified state ERC tracking system shall issue ERCs no less frequently than on an annual basis (i.e., issuance on a shorter basis, such as quarterly or biannual issuance is permissible). (6) Each EM&V report and verification assurance plan shall be submitted on forms and using procedures specified by the plan. (e) Surrender of ERCs. A qualified ERC tracking system must ensure that an affected EGU will place ERCs intended for use in compliance with a plan and sufficient for its compliance demonstration in § 60.5785 in its surrender account prior to the applicable compliance date, and once an ERC is placed in a surrender account, the affected EGU will not be able to remove

the ERC from the account. (f) Retirement of ERCs. A qualified ERC tracking system must retire any ERCs placed in surrender accounts by the compliance date for the affected EGUs pursuant to its plan and ensure that, once an ERC is retired, the ERC shall no longer be transferable to another account on that tracking system or any other tracking system. (g) ERC Transfers. (1) Transfers to/from other qualified ERC tracking systems. A qualified ERC tracking system may accept into its tracking system ERCs from another qualified ERC tracking system and mayPage **1227** of **1275**

preclude such transfers. (2) Transfers to/from an EPA ERC tracking system. To transfer ERCs to/from an EPA CPP ERC tracking system, the qualified state ERC tracking system must be registered for such use by the EPA. (h) ERC Adjustment. A qualified ERC tracking system has at least the following mechanisms in place to make adjustments to the number of qualifying ERCs issued, after generation or savings data is reported to it, and after the ERCs were issued, as data from the prior period are finalized: (1) Any prior period adjustments must be reported to the qualified ERC tracking system by the appropriate reporting entity as soon as possible, with the reason for the adjustment specified and data in support of the adjustment provided. (2) If qualifying ERCs have not yet been created for the original generation amount to which the adjustment applies, the credit or debit adjustment will be reflected in the number of qualifying ERCs issued in the current period. (3) If qualifying ERCs have been created, the credit or debit adjustment will be treated as an adjustment to the number of qualifying ERCs issued to the qualifying affected EGU or ERC generating resource in the prior period. (i) Mechanism to halt issuance. A qualified ERC tracking system has mechanisms in place to temporarily or permanentlyPage **1228** of **1275**

halt issuance of specific ERCs, to remove specific ERC generating resources from its tracking system, and/or to reject the transfer of ERCs that do not meet the requirements of §

60.5791. (j) ERC Information. A qualified ERC tracking system must track, at a minimum, the information in paragraphs (j)(1) through (14) of this section. (1) The ERC tracking system from which the ERC is issued. (2) Account holder name and identification number of ERCs. (3) Qualifying ERC generating resource facility identification number, name, state, and contact information including street address, mailing address, phone number, and

email. (4) Type of qualifying ERC generating resource according to

the definition in section § 60.5840. (5) Date the affected EGU or qualifying ERC generating resource commenced generation or saving of energy. (6) Eligibility of ERCs from qualifying ERC generating resource for compliance with this regulation (7) Quantity of ERCs and fractional roll over ERCs for use in subsequent compliance periods. (8) Unique ERC serial numbers. (9) Vintage of ERCs, with last quarter and year of generation contributing to an accumulated MWh recorded.Page **1229** of **1275**

(10) Parties to each ERC trade, and dates of each ERC

trade. (11) Date an ERC was surrendered. (12) Date an ERC was retired. (13) In the case of a qualifying ERC generator that is producing electrical output for use on a utility grid, the following must be included: (i) The qualifying ERC generating resource generation classification according to the following (if applicable): (A) Generation reported by a control area operator on a unit-specific basis; (B) Small wholesale generation; (C) Wholesale generation also serving on-site loads; or (D) Customer-sited distributed generation. (ii) The data reporting entity type and identity of specific entity (e.g., control area operator, self-reporting). (iii) The maximum electrical generator nameplate capacity in MW; (iv) Information on whether multiple qualifying ERC generating resource generating units are aggregated under one

meter (14) In the case of a qualifying energy saving activity, you must have sufficient tracking requirements for quantification of the MWh of energy saved.Page **1230** of **1275**

(k) Reports. A qualified ERC tracking system provides at least the following reports: (1) EGU Reports. A qualified ERC tracking system commits to provide the ability for each ERC holder to obtain reports of their account activity that includes the information specified in paragraph (e) of this section on at least an annual basis, and provides the ability for each ERC holder to obtain such reports for a period of at least 5 years from the date of ERC

retirement. (2) Public Reports. A qualified ERC tracking system shall provide electronic, internet-based access to the following reports to the public: all registered account holders on the qualified state ERC tracking system, all registered generators on the qualified state ERC tracking system, all qualifying ERC generating resource EM&V plans, all independent third party verifiers, all verification assurance plans, all ERC issuances, all annual aggregate ERC activity statistics on at least an annual basis (issuance of ERCs, trades within the qualified state ERC tracking system, transfers in or out of the qualified state ERC tracking system, and retirements for purpose of this regulation on the qualified state ERC tracking system). The qualified state ERC tracking system shall provide this functionality for as long as this regulation is effective. (3) EPA and state regulator reports. A qualified state ERCPage **1231** of **1275**

tracking system shall provide the ability for the EPA and state regulators to obtain electronically a report that contains comprehensive information regarding all ERCs issued, traded or retired by the qualified state ERC tracking system for purpose of compliance with this regulation, sortable by each of the fields listed paragraph (j) of this section. The qualified state ERC tracking system shall provide this functionality for as long as this regulation is effective. (l) Qualifying ERC generating resource registration requirements. Prior to issuing ERCs from an affected EGU or qualifying ERC generating resource for purpose of compliance with this regulation, a qualified state ERC tracking system shall enter an agreement with the owner or operator of that qualifying ERC generating resource that provides for each of the following: (1) Reporting of 100 percent of the qualifying ERC generating resource’s electrical generation or energy savings to that qualified state ERC tracking system; (2) Annual certification by the owner or operator of the qualifying ERC generating resource that it is registered with only one tracking system for issuance of ERCs, and is eligible to generate ERCs in compliance with § 60.5791; (3) In the case of a qualifying energy ERC generator annual submission of a copy of the qualifying ERC generating resource’sPage **1232** of **1275**

U.S. Energy Information Agency’s Annual Electric Generator Report Form EIA-860 to the qualified state ERC tracking system, or, if the qualifying ERC generating resource generates less than 1 MW/year, annual submission of registration data that would be included on a Form EIA-860 if that entity was required to submit Form EIA-860, (4) Collection of data in accordance with any approved EM&V plan. (5) In the case of a qualifying energy ERC generator, regular inspection of any meters according to appropriate industry protocols to ensure proper operation of the meter, (6) Random inspections and audits of the qualifying ERC generating resource by an independent third party verifier that meets the requirements of § 60.5797, (7) Notification of the qualified state ERC tracking system by the owner or operator of the qualifying ERC generating resource of any change in qualifying ERC generating resource ownership, and the date on which the change occurred, no later than 30 days after the sale closes. (m) Independent third party verifier registration requirements. Prior to issuing ERCs based on a verification assurance plan by an independent third party verifier for purpose of compliance with this regulation, a qualified state ERC tracking system shall enter an agreement with thePage **1233** of **1275**

independent third party verifier that requires the verifier to register with the qualified state ERC tracking system, and meet the requirements of § 60.5797 and § 60.5796 of this subpart. (n) Periodic audits of independent third party verification assurance plans. You must audit the qualified ERC tracking system no less frequently than annually of the content of a 50 % of the verification assurance plans and of at least 50 % of its independent third party verifiers]. Each independent third party verifier registered with its qualified state ERC tracking system shall be audited at least once every 3 years. (1) You, the state must maintain the power to disaccredit or prohibit the use of any specific independent third party verifier in verification work pursuant to this regulation. **§ 60.5795 What are the requirements for EM&V plans?** (a) General EM&V plan and report criteria. A qualifying ERC must be quantified based on energy generation or energy savings from a specific activity, project or program by a qualifying ERC generating resource that is quantified and verified as described in an EM&V plan or report that meets the requirements for that activity, project or program category set forth in § 60.5791, meets credible and appropriate industry-standard practices and guidance documents, and that meets the requirements of this

section. (b) Each EM&V plan or report must describe the specificPage **1234** of **1275**

activity, project or program and identify its location(s) and year(s) of installation and subsequently provide notice of any of the following: (1) A change in energy generation or savings capability of the qualifying ERC generating resource, and the date on which the change occurred, no later than 30 days from when the change is implemented, (2) A change to any of the essential generating or savings characteristics of the qualifying ERC generating resource, where essential generating characteristics shall mean any characteristics that affect the eligibility of the qualifying ERC generating resource for purpose of compliance with this regulation, including the type of qualifying ERC generating resource, and the date of the change. (c) Each EM&V plan or report must describe how the MWh associated with each ERC addressed in that plan or report will be quantified and verified, and each ERC must be quantified and verified based on ex-post energy generation or energy savings. (d) Criteria for a qualifying energy generating resource with a nameplate capacity of 10 kW or more and for a qualifying energy generating resource with a nameplate capacity of less

than 10 kW for which metered data are available. For a qualifying energy generating resource with a nameplate capacity of 10 kW or more, or for a qualifying energy generating resourcePage **1235** of **1275**

with a nameplate capacity of less than 10 kW for which metered data are available, to generate ERCs, its EM&V plan and EM&V reports must demonstrate that the requirements in paragraphs (d)(1) through (6) are met. (1) The generation data was physically measured using a revenue-quality meter, which shall mean 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 for purpose of compliance with this regulation by EPA. (2) The generating data was measured at the generator’s

bus bar. (3) Data from only one qualifying energy generating resource generating unit may be associated with each meter, and generation data may not be aggregated, unless the following provisions are met: (i) All of the generating units have the same essential generation characteristics (ii) 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,

andPage **1236** of **1275**

(iii) The generation data are measured by the same type of

meter. (4) The generation data was collected electronically by either a MV-90 meter data acquisition system or by pulse accumulator readings collected by the control area’s Energy Management System and telemetered from the generator to the control area operator, and the data was verified through a control area energy accounting or settlements process which occurs at least monthly. (5) The generation data was transmitted by a control area operator, and if the control area operator is affiliated with the owner or operator of the qualifying energy generating resource, a person at the control area operator who is precluded from the ability to transfer or retire ERCs issued to that generator. (6) The generation data serves a load that otherwise would have been served by the grid if not for the generator. (i) 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. (ii) 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-Page **1237** of **1275**

site load, if the owner or operator of the qualifying energy generating resource can demonstrate that the metering used is capable of distinguishing between on-site load and station

service. (e) Criteria for a qualifying energy generating resource with a nameplate capacity of less than 10 kW. For a qualifying energy generating resource with a nameplate capacity of less than 10 kW to generate ERCs, its EM&V plan and EM&V reports must demonstrate that the following requirements in paragraphs (e)(1) though (6) are met. (1) Metered data are unavailable. (2) At least 1 MW direct current is generated to the distribution or transmission system over a continuous 365 day period. (3) Generation data may not be aggregated, unless the following provisions are met: (i) The nameplate capacity of the individual units being aggregated is each less than 150 kW, (ii) The units collectively do not exceed a total nameplate capacity of 1 MW when aggregated, (iii) All of the generating units have the same essential generation characteristics, and (iv) The generation data are measured by the same generation estimating software or algorithms.Page **1238** of **1275**

(4) Generation data is 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 size, age, and type of qualifying energy generating

resource. (5) The generation data was self-reported by the qualifying energy resource to its distribution utility and to its distribution utility through an electronic internet-based portal with software that reports total and hourly generation. (6) The generation data serves 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 qualifying energy generating resource to the transmission or distribution grid, and is not based on the generation used on-site by the

customer. (f) Criteria for a qualifying demand-side EE. In the case of qualifying demand-side EE, the following minimum components must be addressed in the EM&V plan or report for the specific activity, project or program (depending on the scope covered by the EM&V plan or report): (1) All demand-side EE savings used to adjust a CO2 emissions rate must be quantified and verified using applicable,Page **1239** of **1275**

credible, and rigorous industry-standard practices and guidance

documents. (2) All savings values must be which determined and reported in units of gross MWh relative to a specified baseline; in cases where gross savings values are not available (e.g., randomized control trials), net savings can be reported. (3) All savings values determined must be determined on a regular basis – at intervals sufficient to credibly document annual savings – by application of one or more non-control group approaches and/or control group approaches. (4) All savings values assessed using deemed savings must be documented in a publicly available database and be reviewed and updated at least every 3 years. The database must indicate, for each value, the conditions for which the value can be applied (i.e., climate, building type, and implementation mechanism). (5) For EE program categories that involve the installation of identifiable measures, verification using industry-standard techniques is required within the first year of program implementation. (6) If transmission and distribution losses are quantified, the adjustment must be based on the lesser of 6 percent of the site-level savings or the calculated statewide annual average transmission and distribution loss rate expressed as aPage **1240** of **1275**

percentage and based on values in the most recent year that is published in the US EIA State Electricity Profile. For transmission and distribution efficiency measures, MWh savings from voltage optimization must be calculated on the basis of industry-standard protocols and procedures identified in an EM&V plan. (7) The duration of EE program or project electricity savings must be determined using periodic verification assessments, industry-standard persistence studies, deemed estimates of effective useful life (EUL), or a combination of

all three. (8) If deemed EUL estimates are used for determining the duration of savings, then zero savings must be assumed at the end of a program, project, or measure life; if project or program persistence studies are conducted at least every 5 years to determine the duration of savings, then savings can be counted as long as the verification activities indicate continued measure operation and performance. (9) All types of double counting must be considered and avoided; documentation of steps taken to avoid double counting must be provided in EM&V plans and EM&V reports. (g) EM&V plans for demand-side EE must describe and document the following: (1) The baseline energy usage conditions, with clearPage **1241** of **1275**

documentation and discussion of the rationale, applicability, and relevant data sources, protocols, and guidance documents used for defining the common practice baseline (CPB). (2) The selected EM&V method, associated assumptions, and data sources used to quantify savings from demand-side EE. (3) How major changes in independent variable conditions that affect energy consumption and savings estimates will be analyzed. (4) How the initial installation of EE will be verified within the first year of implementation for EE program categories that involve the installation of identifiable

measures. (5) How avoided transmission and distribution system losses will be included in EE savings values. (6) How the duration of EE program or project electricity savings will be determined. (7) How the rigor of quantifying MWh savings values will be assessed, and the methods used to control the types of bias or error relevant inherent to the applied EM&V techniques. (8) How double counting will be avoided through the use of tracking and accounting procedures to ensure that two or more programs do not separately claim savings from the same EE project or measure. (9) How the relevant protocols, guidelines, and guidancePage **1242** of **1275**

documents will be applied. (10) Any additional EM&V information needed to ensure that savings from EE programs and projects are credibly quantifiable

and verifiable (h) EM&V reports for demand-side EE must describe and document the following: (1) All demand-side EE savings used to adjust a CO2 emissions rate must be quantified and verified using credible and appropriate industry-standard practices and guidance

documents. (2) EM&V reports must document how applicable EM&V criteria were applied to quantify results. (3) EM&V reports must include after-the-fact documentation of how relevant protocols, guidelines, and guidance documents were actually applied. (4) EM&V report submittals must include any additional EM&V information needed to ensure that savings from EE programs and projects were quantified and verified. (5) At applicable state plan check-in intervals with the EPA (in 2025, 2028, and 2030), states applying conventional EM&V must provide the EPA with access to applicable program- and project-level EM&V reports used to compile total MWh savings and generation. (b) In each EM&V plan, the owner or operator of thePage **1243** of **1275**

affected EGU or qualifying ERC generating resource shall certify the following: (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. **§ 60.5796 What are the requirements for a post-project ERC verification assurance plan?**  (a) Your plan must ensure that all verification assurance plans that verify ERCs shall meet each of the requirements of paragraphs (a)(1) through (8) (1) Verify the eligibility of the specific activity, project or program described in the particular EM&V plan or report for generating ERCs pursuant to this regulation. (2) Verify that the EM&V plan or report meets the requirements of § 60.5795. (3) Verify that the activity, project, or program is in place and has been implemented in accordance with each specificPage **1244** of **1275**

element in the EM&V plan or report (e.g., that the installation rate is met, that the installation meets quality standards, that the measures are operating correctly and have the potential to generate anticipated savings) (4) Review any documents required in the EM&V plan or report and any documents necessary to verify the MWh generated by the qualifying ERC generating resource. (5) Verify any calculations, and the appropriateness of the calculation methodology, used to generate credits. (6) For a qualifying ERC energy resource, verify the metered data specified in of § 60.5795. (7) For a qualifying ERC energy saving activity, verify electricity savings metrics (incremental and cumulative savings). (8) Employ an automatic data validity check to ensure that all generation or savings data from a qualified ERC generating resource is within an acceptable range for that specific generator and that erroneous and technically infeasible data is

not entered. (i) For metered generation, the data validity check shall 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 priorPage **1245** of **1275**

cumulative meter reading was entered in the qualified state ERC tracking system. If the data entered exceeds the estimated technically feasible generation, the generation will be designated “pending” until the reported data and the estimate

are reconciled. (b) Your plan must ensure that the subject of any verification assurance plans, shall not have the opportunity to review or influence any draft or final verification assurance plans before its submittal to the relevant oversight entity, and the independent third party verifier must share any drafts of its reports with the relevant oversight entity at the same time as it shares them with the subject of the report. (c) Your plan must ensure that in each verification assurance plan drafted by an independent third party verifier, the verifier shall certify the following: (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 thePage **1246** of **1275**

possibility of fine or imprisonment. **§ 60.5797 What standards must the independent third party**

**verifier meet?** (a) Your plan must ensure that any verification assurance plan must be drafted by a person (including any corporate parent or subsidiary, any contractors or subcontractors, and the actual person) who meets the following: (1) Is a professional engineer or has other appropriate technical qualification; (2) Is not an, and is not employed by or receiving payment (directly or indirectly) from any, owner or operator of an qualifying ERC generating resource (e.g., a renewable energy resource, an energy efficiency project, etc.) or an affected

EGU; (3) Is free from any interest or the appearance of any interest in any qualifying ERC generating resource (including any role in implementation) or any affected EGU; (4) Has not worked on the development or operation of the subject of the verification; (5) Shall not own, buy, sell, or otherwise trade ERCs used for compliance with a plan or any other credit reflecting any environmental attribute related to the use, generation or saving of electricity; (6) Attests, in its verification report, to compliance withPage **1247** of **1275**

the American Evaluation Association requirements for verification; and (7) Has not been debarred, suspended, or proposed for debarment pursuant to the Government-wide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4. (b) Your plan must ensure that any qualified state ERC tracking system and any independent third party verifier must maintain, for its employees, and must ensure the maintenance of, for any parties that it employs, professional liability insurance, as defined in 31 C.F.R. 50.5(q), through an insurance provider that possess 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 shall disclose the level of professional liability insurance they possess when entering into contracts to provide verification services pursuant to this regulation. **Applicability of Plans to Affected EGUs § 60.5800 Does this subpart directly affect EGU owners or**  **operators in my state?** (a) This subpart does not directly affect EGU owners or operators in your state. However, affected EGU owners orPage **1248** of **1275**

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, or EPA disapproves, a final plan or initial plan submittal to implement and enforce the emission guidelines contained in this subpart by August 31, 2016, the EPA will implement and enforce a Federal plan, as provided in § 60.5720, to ensure that each affected EGU within the state that commenced construction on or before January 8, 2014 complies with all the provisions of this subpart. **§ 60.5805 What affected EGUs must I address in my state plan?** (a) The EGUs that must be addressed by your plan are any affected steam generating unit, IGCC, or stationary combustion turbine that commences construction on or before January 8,

2014. (b) An affected EGU is a steam generating unit, integrated gasification combined cycle (IGCC), or stationary combustion turbine that meets the relevant applicability conditions specified in paragraph (b)(1) through (3) of this section. (1) Serves a generator connected to a utility power distribution system with a nameplate capacity of 25 MW-net or greater (i.e., capable of selling greater than 20 MW of electricity);Page **1249** of **1275**

(2) Has a base load rating (i.e., design heat input capacity) greater than 260 GJ/hr (250 MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and (3) Stationary combustion turbines that meet the definition of either a combined cycle or combined heat and power combustion

turbine. **§ 60.5810 What affected EGUs are exempt from my state plan?** (a) Affected EGUs that are exempt from your plan include: (1) EGUs that are subject to subpart TTTT as a result of commencing construction after the subpart TTTT applicability date; and those subject to subpart TTTT as a result of commencing modification or reconstruction; (2) Steam generating units and IGCC units that are currently and always have been subject to a federallyenforceable permit limiting annual net-electric sales to onethird or less of its potential electric output or 219,000 MWh or less; (3) Stationary combustion turbines not capable of combusting natural gas (e.g., not connected to a natural gas pipeline) (4) Your EGU is capable of combusting 50 percent or more non-fossil fuel and subject to a federally enforceable permitPage **1250** of **1275**

limiting, or has historically limited, fossil fuel use to 10% or less of the annual capacity factor; (5) EGUs that are a combined heat and power unit that is subject to a federally enforceable permit limiting, or has historically limited, annual net-electric sales to a utility distribution system to the design efficiency times the potential electric output or 219,000 MWh (whichever is greater) or less; (6) 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; (7) EGUs that are a municipal waste combustor unit that is subject to subpart Eb of this part; and (8) EGUs that are a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part. **§ 60.5815 What are the CO 2**  **emissions performance rates for**

**affected EGUs?** (a) You must require, in your plan, affected EGUs to meet

CO 2 emission performance rates listed in table 1 of this subpart except as provided in paragraph (b) of this section. (b) You may elect to demonstrate that affected EGUs are meeting their CO 2 emission performance rate by achieving statewide emission goals which are equivalent and no lessPage **1251** of **1275**

stringent than the CO 2 emission performance rates listed in table 1. Your equivalent statewide CO 2 emission goals may take the following forms: (1) Average statewide rate-based CO 2 emission goals listed in table 2 of this subpart, except as provided in paragraph (c) and (d); or (2) Cumulative statewide mass-based CO 2 emission goals listed in table 3 of this subpart, except as provided in paragraph (c) and (d). (c) If your plan incorporates CO 2 emission goals listed in paragraphs (b)(1) or (2) of this section you may elect to develop your own interim step goals if you do not wish to adopt the interim step goals provided in paragraph (b)(1) or (b)(2). Additionally the following applies if you elect to develop your own goals: (1) The interim period and interim steps CO 2 emission goals must be in the same form, either both rate (in units of pounds per net MWh) or both mass (in tons); and (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 goal. (3) The initial and final CO 2 emission goals that you elect to achieve in your plan may take different forms between the interim period and final period (e.g., a rate-based goal for thePage **1252** of **1275**

interim period and a mass-based goal for the final period), however, the form of a state CO 2 emission goal in your plan may not be changed once a relevant period has begun. (d) Your plans interim period and final period CO 2 emission goals included in a plan that your state or states elects to achieve may be changed in the plan only according to situations listed in paragraphs (d)(1) and (2) of this section. If a situation requires a plan revision you must follow the procedures in § 60.5785 to submit a plan revision. (1) If your plan implements CO 2 emission goals for your affected EGUs to meet, you may submit state plan revisions to make corrections to your state goal, which result in no more than a 2 percent change in the state goal; and (2) You may address EGUs that become subject to subpart TTTT of this Part and are no longer considered affected EGUs for incorporation in a plan. **§ 60.5820 What applicable monitoring, recordkeeping, and reporting requirements do I need to include in my plan for** 

**affected EGUs?** (a) Your plan must include monitoring for affected EGUs that is no less stringent that what is described in (a)(1) through (6) of this section. (1) The owner of operator of an affected EGU required to meet a rate based emission standard they must prepare aPage **1253** of **1275**

monitoring plan in accordance with the applicable provisions in § 75.53(g) and (h) of this chapter. (2) The owner or operator of an affected EGU must measure the hourly CO 2 mass emissions from each affected unit using the procedures in paragraphs (a)(2)(i) through (v) of this section, except as provided in paragraph (a)(3) of this section. (i) The owner or operator of an affected EGU must install, certify, operate, maintain, and calibrate a CO 2 continuous emissions monitoring system (CEMS) to directly measure and

record CO 2 concentrations in the affected EGU exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to § 75.10(a)(3)(i) of this chapter. If the owner or operator of an affected EGU measures CO 2 concentration on a dry basis, they must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to § 75.11(b) of this chapter. (ii) For each monitoring system the owner or operator uses

to determine the CO 2 mass emissions from an affected EGU uses, the monitoring system must meet the applicable certification and quality assurance procedures in § 75.20 of this chapter and Appendices B and D to part 75 of this chapter. (iii) The owner operator of an affected EGU must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions from the affected facility; the ownerPage **1254** of **1275**

or operator of an affected EGU must not apply the bias adjustment factors described in section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust gas flow rate data. (3) The owner or operator of an affected EGU may determine site-specific carbon-based F-factors (F c ) using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter, and may

use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature. (4) 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. (5) 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 ownerPage **1255** of **1275**

or operator may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If an owner or operator of an affected EGU chooses this option, the hourly net electric output for the common stack must be the sum of the hourly net electric output of the individual affected facility and the operating time must be expressed as “stack operating hours” (as defined in § 72.2 of this chapter). (6) 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 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct must be monitored separately. In this case, the owner or operator of an affected EGU must determine compliance with an applicable emissions standard by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the net energy output

for the affected EGU. (b) The owner or operator of an affected EGU must maintain records, as required by a plan, for at least 5 years following the date of each compliance period, occurrence, measurement, maintenance, corrective action, report, or record.Page **1256** of **1275**

(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, 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: (i) All documents, data files, and calculations and methods used to demonstrate compliance with an affected EGU’s emission

standard under § 60.5790. (ii) Copies of all reports submitted to the state under paragraph (c) of this section. (iii) Data that is required to be recorded by 40 CFR Part 75 Subpart F. (iv) Data with respect to any ERCs (if applicable) including the information in paragraphs (b)(2)(iv)(A) through (C) of this section. (A) All correspondence and other commercial documents related to any ERC transactions that involved qualifying ERCs and any EM&V plans related to those ERCs. (B) All independent third party verifier verification assurance plans.Page **1257** of **1275**

(C) All records and reports relating to the surrender and retirement of ERCs for compliance with this regulation, and all information specified in § 60.5793(j). (c) The owner or operator of an affected EGU must include in a report required by the plan covering each compliance period all hourly CO 2 emissions, all hourly net electric output and all hourly net energy output measurements for a CHP facility calculated from data monitored according to paragraph (a) of this section according to the procedures in 40 CFR Part 75 Subpart G. In addition a plan must require reports to be

submitted from the EGUs that include the information in paragraphs (c)(1) and (2) of this section. (1) For each affected EGU’s compliance period, owners and operators of affected EGUs must include in their report their applicable emission standard calculated as a CO 2 emission rate or cumulative mass in units of the standard required in § 60.5790. (2) If the owner or operator of an affected EGU is complying with an emission standard by using ERCs they must include in their report a list of all ERC serial numbers retired for the compliance period that an affected EGU used to comply with an emission standard, and all other information specified in § 60.5793(e) of this section. (d) The owner or operator of an affected EGU must follow any additional requirements for monitoring, recordkeeping andPage **1258** of **1275**

reporting in a plan that are required under § 60.5785, if applicable. **Recordkeeping and Reporting Requirements § 60.5825 What are my state recordkeeping requirements?**  (a) States 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 steps 1, 2 and 3 and the interim plan period from 2022- 2029. After 2029 states must keep records of all information relied upon in support of any continued demonstration that the final emissions goals are being achieved. (b) States 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 state requirement. (c) If a state has a requirement for hourly CO 2 emissions and net generation information to be used to calculate compliance with an annual emissions standard for affected EGUs, any information that is submitted by the owners or operators of affected EGUs to the EPA electronically pursuant to requirements in Part 75 meets the recordkeeping requirement of this section and a state is not required to keep records of information that would be in duplicate of paragraph (b) of this section.Page **1259** of **1275**

(d) A state 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 or goal in the interim period. **§ 60.5830 What are my state reporting requirements?** (a) In lieu of the annual report required under § 60.25 (e) and (f) you must report the information in paragraphs (b) through (e) 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 reporting covering interim step 1 (2022-2024) due no later than July 1, 2025. The final period reports start with a 2030-2031 bi-annual report (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 2 emission performance rate

or CO 2 emission goal (as applicable). The report must include the following: (1) 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 affected EGUs are on schedule to meet the applicable CO 2 emissionPage **1260** of **1275**

performance rate or emission goal during the performance periods and compliance periods, as specified in the plan. (2) A comparison of the CO 2 emission performance rate or CO 2 emission goal identified in the state plan for the applicable interim step period versus the actual average or cumulative CO 2 emission performance (as applicable) achieved by all affected

EGUs. (3) All other required information, as specified in your state plan according to §60.5740(a)(5). (c) If your plan includes state measures, in lieu of or in addition to emission standards, than you must submit an annual report to the EPA in addition to the reports required under paragraph (b) for the interim period. In the final periods you must submit bi-annual reports consistent with those required under paragraph (b). The annual reports in the interim period must be submitted no later than July 1 following the end of each calendar year starting with the annual year 2022 (January 1, 2022 to December 31, 2022). The annual and bi-annual reports must include the information in paragraphs (c)(1) and (2) of

this section. (1) You must include in your report the status of implementation of federally enforceable emission standards (if applicable) and state measuresPage **1261** of **1275**

(2) You must include information regrinding 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 than you must submit a notification in the report required under paragraph (b) of this section to the EPA if your affected EGUs exceed a CO 2 emission performance rate or CO 2 emission goal (on average for rate or cumulatively for mass) by 10 percent or greater thus triggering corrective measures required under your plan. If corrective measures are required you must follow the requirements in 60.5785 for revising your plan to implement the corrective

measures. (e) If your plan includes 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) or 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 yourPage **1262** of **1275**

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 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 your affected EGUs, at the end of any interim performance step or final period, exceed a CO 2 emission performance rate or CO 2 emission goal (on average for rate or cumulatively for mass) by 10 percent or greater thus triggering the implementation of the backstop required in your plan. This notification must detail the implementation of the backstop 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 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 emissions or cumulative sum of emissions over the 2022-2029 interim period used to determine compliance with your interim CO 2 emission performance rate or emission goal. The calculated value must be in units consistent with the approach you set in your plan for the interim period.Page **1263** of **1275**

**§ 60.5835 How do I submit information required by these Emission**

**Guidelines to the EPA?** (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 and any state reports must be reported through EPA’s State Plan Electronic Collection System (SPeCS). Confidential business information that is part of an official submittal to EPA must also be submitted electronically into the SPeCS. (c) Only a submittal by the Governor’s 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 August 31, 2016, deadline for plan submittal so that they 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 namePage **1264** of **1275**

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 shall 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 shall provide the EPA with 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 planPage **1265** of **1275**

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.

**Definitions § 60.5840 What definitions apply to this subpart?**  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 (General Provisions) and B of this part. Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Affected electric generating unit or Affected EGU means a steam generating unit, an IGCC facility, or a stationary combustion turbine that meets the applicability conditions in

section § 60.5800. Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis, as determined by the physical design and characteristics of the EGU at ISO conditions. For a stationary combustion turbine , base load rating includes the heat input from duct burners.

CO 2 emission goal means a statewide rate-based CO 2 emissionPage **1266** of **1275**

goal or mass-based CO2 emission goal specified in § 60.5815.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-oil mixtures,

and coal-water mixtures are included in this definition for the purposes of this subpart. Combined cycle unit means an electric generating unit that

uses a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. Combined heat and power unit or CHP unit, ( also known as “cogeneration”) means an electric generating unit that use a steam-generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. Control area operator means an electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other control areas and contributing to frequency regulation of

the interconnection.Page **1267** of **1275**

Design efficiency means the rated overall net efficiency (e.g., electric plus thermal output) on a higher heating value basis of the EGU at the base load rating and ISO conditions.

Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17). Essential generating characteristics means any characteristic that affects the eligibility of the qualifying energy generating resource for generating ERCs pursuant to this regulation, including the type of resource. Existing state program, requirement, or measure means, in the context of a state plan, a regulation, requirement, program, or measure administered by a state, utility, or other entity that is currently established. This may include a regulation orPage **1268** of **1275**

other legal requirement that includes past, current, and future obligations, or current programs and measures that are in place and are anticipated to be continued or expanded in the future, in accordance with established plans. An existing state program, requirement, or measure may have past, current, and future impacts on EGU CO 2 emissions.

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal. Heat recovery steam generating unit (HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used

with or without duct burners. Integrated gasification combined cycle facility or IGCC facility means a combined cycle facility that is designed toburn fuels containing 50 percent (by heat input) or more solidderived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment.Page **1269** of **1275**

The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.

ISO conditions means 288 Kelvin (15 o C), 60 percent relative humidity and 101.3 kilopascals pressure. Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate

oil and residual oil. Mechanical output means the useful mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal output, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blastPage **1270** of **1275**

furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Net-electric output means the amount of gross generation the generator(s) produce (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and

transformer losses as measured at the transmission side of the step up transformer (e.g., the point of sale).

Net energy output means:

(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 (e.g., steam delivered to an industrial process for a heating application). (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,Page **1271** of **1275**

the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; (e.g., steam delivered to an industrial process for a heating application).

Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil. Qualifying energy generating resource means: (1) An affected EGU, (2) Electric generating technologies using renewable energy resources, such as wind, solar, geothermal, hydro, wave, and tidal power, (3) Biomass co-firing or repowering, (4) Nuclear power, and (5) Waste heat power. Qualifying energy savings measure means a demand-side energy efficiency or demand-side management measure that saves electricity and is calculated on the basis of ex poste savings, not “projected” or “claimed” savings. Qualifying ERC generating resource means a resource or measure that may generate ERCs that (a) began generating electricity or had a capacity uprate no earlier than January 1, 2013 (in the case of a qualifying energy generating resource) or began saving energy no earlier than January 1, 2013 (in case of a qualifying energy saving measure), and (b) is connected to,Page **1272** of **1275**

and delivers energy to or saves electricity, on the continental electric grid in the United States.

Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized

solid fuels. Standard ambient temperature and pressure (SATP)

conditions means 298.15 Kelvin (25 o C, 77 o F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. State agent means an entity acting on behalf of the state, with the legal authority of the state

State measures means measures that the state adopts and implements as a matter of state law. Such measures are enforceable only per state law, and are not included in and codified as part of the federally enforceable state plan. Stationary combustion turbine means all equipment, including but not limited to the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emissionscontrol technology, and any ancillary components and subcomponents comprising any simple cycle stationary combustionPage **1273** of **1275**

turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit. Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. Useful thermal output means the thermal energy made available for use in any heating application (e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device atPage **1274** of **1275**

the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.

**Table 1 to Subpart UUUU of Part 60—CO 2**  **Emission Performance Rates (Pounds of CO**  **2 Per Net MWh)** 

**Affected EGU I**  **nterim Rate Final Rate Steam generating**  **unit or integrated gasification**  **combined cycle (IGCC)**  [X] 1290

**Stationary combustion turbine**  [X] 780

**Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO 2**  **Emission Goals (Pounds of CO 2**  **Per Net MWh)** [Placeholder for table]Page **1275** of **1275**

**Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO 2**  **Emission Goals (Short Tons of CO 2**  **)** [Placeholder for table]