# Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2018-27052 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** December 20, 2018 - **Citation:** 83 FR 65424 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 60 [EPA-HQ-OAR-2013-0495; FRL-9987-85-OAR] RIN 2060-AT56 Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed rule. SUMMARY: The Environmental Protection Agency (EPA) is proposing amendments to the rulemaking titled “Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (EGUs),” which the EPA promulgated by notice dated October 23, 2015 ( i.e., the 2015 Rule). Specifically, the EPA proposes to amend its previous determination that the best system of emission reduction (BSER) for newly constructed coal-fired steam generating units ( i.e., EGUs) is partial carbon capture and storage (CCS). Instead, the EPA proposes to find that the BSER for this source category is the most efficient demonstrated steam cycle ( e.g., supercritical steam conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices. The EPA proposes to revise the standard of performance for newly constructed steam generating units as separate standards of performance for large and small steam generating units that reflect the Agency's amended BSER determination. In addition, the EPA proposes to revise the standard of performance for reconstructed steam generating units to be separate standards of performance for reconstructed large and small steam generating units, consistent with the proposed revised standards for newly constructed steam generating units. The EPA also proposes separate standards of performance for newly constructed and reconstructed coal refuse-fired EGUs. In addition, the EPA proposes to revise the maximally stringent standards for large modifications of steam generating units to be consistent with the standards for reconstructed large and small steam generating units. The EPA is not proposing to amend and is not reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. The EPA is also proposing to make other miscellaneous technical changes in the regulatory requirements. DATES: Comments. Comments must be received on or before February 19, 2019. Public Hearing. The EPA is planning to hold at least one public hearing in response to this proposed action. Information about the hearing, including location, date, and time, along with instructions on how to register to speak at the hearing, will be published in a second Federal Register notice. ADDRESSES: Comments. Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2013-0495, at https://www.regulations.gov. Follow the online instructions for submitting comments. Once submitted, comments cannot be edited or removed from Regulations.gov . See SUPPLEMENTARY INFORMATION for detail about how the EPA treats submitted comments. Regulations.gov is our preferred method of receiving comments. However, other submission methods are accepted: • Email: a-and-r-docket@epa.gov. Include Docket ID No. EPA-HQ-OAR-2013-0495 in the subject line of the message. • Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-2013-0495. • Mail: To ship or send mail via the United States Postal Service, use the following address: U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2013-0495, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460. • Hand/Courier Delivery: Use the following Docket Center address if you are using express mail, commercial delivery, hand delivery, or courier: EPA Docket Center, EPA WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. Delivery verification signatures will be available only during regular business hours. FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Mr. Christian Fellner, Sector Policies and Programs Division (Mail Code D205-01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-4003; fax number: (919) 541-4991; and email address: fellner.christian@epa.gov. For information about the applicability of the new source performance standards (NSPS) to a particular entity, contact Sara Ayres, U.S. Environmental Protection Agency, Region 5, 77 West Jackson Boulevard (Mail Code E-19J), Chicago, Illinois 60604-3507; telephone number (312) 353-6266; and email address: ayres.sara@epa.gov. SUPPLEMENTARY INFORMATION: Docket. The EPA has established a docket for this rulemaking under Docket ID No. EPA-HQ-OAR-2013-0495. All documents in the docket are listed in Regulations.gov . Although listed, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in Regulations.gov or in hard copy at the EPA Docket Center, Room 3334, EPA WJC West Building, 1301 Constitution Avenue NW, Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the EPA Docket Center is (202) 566-1742. Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-2013-0495. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at https://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through https://www.regulations.gov or email. This type of information should be submitted by mail as discussed below. The EPA may publish any comment received to its public docket. Multimedia submissions (audio, video, etc. ) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission ( i.e., on the Web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets. The https://www.regulations.gov website allows you to submit your comments anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https://www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets. The EPA is soliciting comment on numerous aspects of the proposed rule. The EPA has indexed each comment solicitation with an alpha-numeric identifier ( e.g., “C-1,” “C-2,” ”C-3,” . . .) to provide a consistent framework for effective and efficient provision of comments. Accordingly, the EPA asks that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. The EPA asks that commenters include the identifier in either a heading, or within the text of each comment ( e.g., “In response to solicitation of comment C-1, . . .”) to make clear which comment solicitation is being addressed. The EPA emphasizes that the Agency is not limiting comment to these identified areas and encourage provision of any other comments relevant to this proposal. 1 1 In this proposal, in some instances, the EPA identifies an issue that the Agency has previously addressed, and states that the Agency is not re-opening that issue in this proposal. The EPA will not consider such an issue as relevant to this proposal. Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov or email. Clearly mark the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, mark the outside of the digital storage media as CBI and then identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in Instructions above. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver information identified as CBI only to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2013-0495. Preamble Acronyms and Abbreviations. The EPA uses multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: AEO Annual Energy Outlook BACT best available control technology BSER best system of emission reduction Btu/kWh British thermal units per kilowatt-hour Btu/lb British thermal units per pound °C degrees Celsius CAA Clean Air Act CAAA Clean Air Act Amendments CAMD Clean Air Markets Division CBI confidential business information CBO Congressional Budget Office CCS carbon capture and storage (or sequestration) CEMS continuous emissions monitoring system CFB circulating fluidized bed CFR Code of Federal Regulations CH 4 methane CHP combined heat and power CO carbon monoxide CO 2 carbon dioxide CSP concentrated solar power DC District of Columbia D.C. Circuit United States Court of Appeals for the District of Columbia Circuit DOE Department of Energy ECMPS emissions collection and monitoring plan system EGU electric utility generating unit EIA U.S. Energy Information Administration EOR enhanced oil recovery EPA Environmental Protection Agency °F degrees Fahrenheit FB fluidized bed FGD flue gas desulfurization FLGR TM fuel lean gas reburning GHG greenhouse gas GHGRP Greenhouse Gas Reporting Program GJ/h gigajoules per hour GPM gallons per minute GS geologic sequestration GW gigawatts H 2 hydrogen gas HAP hazardous air pollutant(s) HFC hydrofluorocarbon Hg mercury HRSG heat recovery steam generator ICR information collection request IGCC integrated gasification combined cycle IRPs Integrated Resource Plans km kilometers lb CO 2 /MMBtu pounds of CO 2 per million British thermal units lb CO 2 /MWh pounds of CO 2 per megawatt-hour lb CO 2 /MWh-gross pounds of CO 2 per megawatt-hour on a gross output basis lb CO 2 /MWh-net pounds of CO 2 per megawatt-hour on a net output basis LCOE levelized cost of electricity M million MMBtu/h million British thermal units per hour MPa megapascals MW megawatts MWh megawatt-hours MW net megawatts-net N 2 molecular nitrogen N 2 O nitrous oxide NAAQS national ambient air quality standards NAICS North American Industry Classification System NETL National Energy Technology Laboratory NGCC natural gas combined cycle NGR natural gas reburning NO X nitrogen oxides NSPS new source performance standards NTTAA National Technology Transfer and Advancement Act O&M operation and maintenance OAQPS Office of Air Quality Planning and Standards OFA overfire air OMB Office of Management and Budget PC pulverized coal PFC perfluorocarbon PM particulate matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration psi pounds per square inch psig pounds per square inch gauge QA quality assurance RCRA Resource Conservation and Recovery Act RFA Regulatory Flexibility Act SBA Small Business Administration SCCFB supercritical circulating fluidized bed SCE&G South Carolina Electric and Gas SCPC supercritical pulverized coal SCR selective catalytic reduction SF 6 sulfur hexafluoride SO 2 sulfur dioxide SSM startup, shutdown, and malfunction T&S transmission and storage TSD technical support document UAMPS Utah Associated Municipal Power Systems µg/m 3 micrograms per cubic meter UMRA Unfunded Mandates Reform Act of 1995 U.S. United States U.S.C. United States Code VCS voluntary consensus standard Organization of this Document. The information in this preamble is organized as follows: I. General Information A. Executive Summary B. Types of Sources C. The 2015 Rulemaking, Reconsideration, and Litigation D. The Purpose of This Regulatory Action E. Does this action apply to me? F. Where can I get a copy of this document and other related information? II. Proposed Requirements for New, Reconstructed, and Modified Sources A. Applicability Requirements B. Emission Standards III. Legal Authority A. Statutory Background B. Authority To Revise Existing Regulations C. Authority To Regulate CO 2 From Fossil Fuel-Fired EGUs IV. Rationale for Proposed Applicability Criteria V. Rationale for Proposed Emission Standards for New and Reconstructed Fossil Fuel-Fired Steam Generating Units A. Review of the 2015 BSER Analysis B. Identification of the Revised BSER C. Reconstructed EGUs D. Coal Refuse Subcategory E. Determination of the Level of the Standard F. Format of the Output-Based Standard VI. Rationale for Proposed Emission Standards for Modified Fossil Fuel-Fired Steam Generating Units A. Identification of the BSER B. Determination of the Level of the Standard VII. Interactions With Other EPA Programs and Rules VIII. Summary of Cost, Environmental, and Economic Impacts A. What are the air impacts? B. What are the energy impacts? C. What are the compliance costs? D. What are the economic and employment impacts? E. What are the benefits of the proposed standards? IX. Request for Comments A. Subcategorization by Fuel Type B. Low Duty Cycle Subcategory C. Commercial Demonstration Permit D. Applicability to Industrial EGUs E. Non-Sequestration of Captured Carbon F. Additional Amendments G. Non-Base Load Combustion Turbines X. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Executive Order 13771: Reducing Regulation and Controlling Regulatory Costs C. Paperwork Reduction Act (PRA) D. Regulatory Flexibility Act (RFA) E. Unfunded Mandates Reform Act (UMRA) F. Executive Order 13132: Federalism G. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use J. National Technology Transfer and Advancement Act (NTTAA) K. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations XI. Statutory Authority I. General Information A. Executive Summary 1. Proposed Revisions to the 2015 Rulemaking The EPA is revisiting several portions of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (EGUs), which was promulgated on October 23, 2015 (80 FR 64510). First, for newly constructed fossil fuel-fired electric utility steam generating units that are either utility boilers or integrated gasification combined cycle (IGCC) units, the EPA proposes to revise the BSER to be the most efficient demonstrated steam cycle ( i.e., supercritical steam conditions for large EGUs and best available subcritical steam conditions for small EGUs) 2 in combination with the best operating practices, instead of partial CCS. The primary reason for this proposed revision is the high costs and limited geographic availability of CCS. Based on the proposed revisions to the BSER, the EPA is proposing to establish revised ( i.e., higher) emission rates as the standards of performance for large and small EGUs ( See Table 1). Further, for EGUs that undertake a reconstruction, because the standards for reconstructed EGUs are also based on best available efficiency technology, the EPA is proposing to revise those standards to consist of higher emission rates for large and small EGUs to be consistent with the standards for newly constructed EGUs ( See Table 1). The EPA also proposes separate standards of performance for newly constructed and reconstructed coal refuse-fired EGUs ( See Table 1). In addition, while the EPA is not proposing to revise the BSER identified in the 2015 Rule (which is based on the individual EGU's best demonstrated performance) for fossil fuel-fired electric utility steam generating units that undertake large modifications 3 ( i.e., modifications that result in an increase in hourly emissions of more than 10 percent), the EPA proposes to revise the maximally stringent standards 4 (that is, the level that is the most stringent that the standard can be) to be consistent with the proposed revised standards for new and reconstructed EGUs ( See Table 1). Additionally, the EPA proposes minor amendments to the applicability criteria for combined heat and power (CHP) and non-fossil EGUs to reflect the original intended coverage. Finally, with respect to EGUs that undertake small modifications ( i.e., modifications that result in an increase in hourly emissions of 10 percent or less) for which standards were not included in the 2015 Rule, the EPA is soliciting comment on standards of performance based on a unit's historical performance and how to best account for emissions variability due to changes in the mode of operation (Comment C-1). Table 1 shows the proposed emission standards for newly constructed and reconstructed EGUs, as well as modified EGUs. 2 A subcritical EGU operates at pressures where water first boils and is then converted to superheated steam. A supercritical steam generator EGU operates at pressures in excess of the critical pressure of water and heats water to produce superheated steam without boiling. While often referred to as a supercritical boiler, no boiling actually occurs in the device and the term “boiler” should technically not be used for a supercritical pressure steam generator. Note: the term “EGU” is intended to refer to the affected facility (also referred to as the affected “source” or “unit”). 3 Under 40 CFR 60.14(h), a modification of an existing electric utility steam generating unit is defined as a physical change or change in the method of operation of the unit that increases the maximum hourly emissions of any regulated pollutant above the maximum hourly emissions achievable at that unit during the 5 years prior to the change. 4 The maximally stringent standard for modified EGUs is the numeric standard for reconstructed EGUs, even if the emission rate based on best annual performance is lower than that numeric standard. Table 1—Summary of BSER and Proposed Standards for Affected Sources Affected source BSER Emissions standard New and Reconstructed Steam Generating Units and IGCC Units Most efficient generating technology in combination with best operating practices 1. 1,900 lb CO 2 /MWh-gross for sources with heat input >2,000 MMBtu/h. 2. 2,000 lb CO 2 /MWh-gross for sources with heat input ≤2,000 MMBtu/h OR 3. 2,200 lb CO 2 /MWh-gross for coal refuse-fired sources. Modified Steam Generating Units and IGCC Units Best demonstrated performance A unit-specific emission limit determined by the unit's best historical annual CO 2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than: 1. 1,900 lb CO 2 /MWh-gross for sources with heat input >2,000 MMBtu/h. 2. 2,000 lb CO 2 /MWh-gross for sources with heat input ≤2,000 MMBtu/h OR 3. 2,200 lb CO 2 /MWh-gross for coal refuse-fired sources. The EPA is not proposing to amend and is not reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. The EPA is also proposing to make other miscellaneous technical changes to the regulations. 2. Costs and Benefits When the EPA promulgated the 2015 Rule, it took note of both utility announcements and U.S. Energy Information Administration (EIA) modeling and, based on that information, concluded that “even in the absence of this rule, (i) existing and anticipated economic conditions are such that few, if any, fossil-fuel-fired steam-generating EGUs will be built in the foreseeable future,” and that “(ii) utilities and project developers are expected to choose new generation technologies (primarily NGCC) that would meet the final standards” and also “renewable generating sources that are not affected by these final standards.” See 80 FR 64515. The EPA, therefore, projected that the 2015 Rule would “result in negligible CO 2 emission changes, quantified benefits, and costs by 2022 as a result of the performance standards for newly constructed EGUs.” Id. The Agency went on to say that it had been “notified of few power sector NSPS modifications or reconstructions.” Based on that additional information, the EPA said it “expects that few EGUs will trigger either the modification or the reconstruction provisions” of the 2015 Rule. Id. at 64516. The EPA believes that the projections it made in conjunction with its promulgation of the 2015 Rule remain generally correct, in that, as explained in the economic impact analysis for this proposed rule, in the period of analysis, recent EPA and EIA analyses project there to be, at most, few new, reconstructed, or modified sources that will trigger the provisions the EPA is proposing. Consequently, the EPA has conducted an illustrative analysis of the costs for a representative new unit. Based on this analysis, which is presented in the economic impact analysis, the EPA projects this proposed rule will not result in any significant carbon dioxide (CO 2 ) emission changes or costs. This analysis reflects the best data available to the EPA at the time the modeling was conducted. As with any modeling of future projections, many of the inputs are uncertain. In this context, notable uncertainties, in the future, include the cost of fuels, the cost to operate existing power plants, the cost to construct and operate new power plants, infrastructure, demand, and policies affecting the electric power sector. The modeling conducted for this economic impact analysis is based on estimates of these variables, which were derived from the data currently available to the EPA. However, future realizations could deviate from these expectations as a result of changes in wholesale electricity markets, federal policy intervention, including mechanisms to incorporate value for onsite fuel storage, or substantial shifts in energy prices. The results presented in this economic impact analysis are not a prediction of what will happen, but rather a projection describing how this proposed regulatory action may affect electricity sector outcomes in the absence of unexpected shocks. The results of this economic impact analysis should be viewed in that context. B. Types of Sources Fossil fuel-fired EGUs take two forms that are relevant for present purposes: Those that are steam generating units and those that use gasification technology. 5 Fossil fuel-fired steam generating units can burn natural gas, oil, or coal. However, coal is the dominant fuel for electric utility steam generating units. Coal-fired steam generating units are primarily either pulverized coal (PC) or fluidized bed (FB) steam generating units. 6 At a PC steam generating unit, the coal is crushed (pulverized) into a powder to increase its surface area. The coal powder is then blown into a steam generating unit and burned. In a fossil fuel-fired steam generating unit using FB combustion, the solid fuel is burned in a layer of heated particles suspended in flowing air. Power can also be generated from coal or other fuels using gasification technology. An IGCC unit gasifies coal or petroleum coke to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H 2 ), which can be combusted in a combined cycle system to generate power. 5 Fossil fuel-fired EGUs also include combustion turbines, but the EPA is not proposing any changes to standards for those types of sources in this rulemaking. 6 Fossil fuel-fired utility steam generating units ( i.e., boilers) are most often operated using coal as the primary fuel. However, some utility boilers use natural gas and/or fuel oil as the primary fuel. Natural gas-fired EGUs typically use one of two technologies: Natural gas combined cycle (NGCC) or simple cycle combustion turbines. NGCC units first generate power from a combustion turbine engine (the combustion cycle). 7 The unused heat from the combustion turbine engine is then routed to a heat recovery steam generator (HRSG) that generates steam, which is then used to produce power using a steam turbine (the steam cycle). Combining these generation cycles increases the overall efficiency of the system. Simple cycle combustion turbines only use a combustion turbine engine to produce electricity ( i.e., there is no heat recovery or steam cycle). 7 Note that natural gas can also be used as a fuel in a steam generating EGU (boiler) and many existing coal- and oil-fired utility boilers have repowered as natural gas-fired units. However, a natural gas-fired utility boiler is not currently an economically or technologically viable choice for construction of a new steam generating unit EGU (80 FR 64515). C. The 2015 Rulemaking, Reconsideration, and Litigation On April 13, 2012, the EPA first proposed a NSPS for greenhouse gas (GHG) emissions from fossil fuel-fired EGUs (77 FR 22392). That proposal identified as the BSER for a coal-fired power plant building a natural gas-fired power plant ( Id. at 22394). On January 8, 2014, the EPA rescinded that proposal and replaced it with a supplemental proposal that identified partial CCS as the BSER for coal-fired power plants 8 (79 FR 1430). On October 23, 2015, the EPA finalized the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Generating Units (80 FR 64510). In that action, the EPA issued final standards of performance to limit emissions of GHG pollution manifested as CO 2 9 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units ( i.e., utility boilers and IGCC EGUs) and newly constructed and reconstructed stationary combustion turbine EGUs. These final standards are codified in 40 CFR part 60, subpart TTTT. 8 The applicability includes all fossil fuel-fired steam generating units ( e.g., natural gas and oil-fired EGUs), but the BSER determination focused on coal-fired EGUs. 9 Greenhouse gas pollution is the aggregate group of the following gases: CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6 ), hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). The 2015 standards of performance for newly constructed fossil fuel-fired steam generating units 10 were based on the performance of a new, highly efficient, supercritical pulverized coal (SCPC) EGU, implementing post-combustion partial CCS technology, which the EPA determined to be the BSER under Clean Air Act (CAA) section 111(b) for these sources. The EPA concluded that CCS was adequately demonstrated (including being technically feasible) and widely available, and could be implemented at reasonable cost. The EPA did not determine natural gas co-firing or IGCC technology (either with natural gas co-firing or implementing partial CCS) to be BSER. However, the Agency did identify them as alternative methods of compliance. 10 The EPA also refers to fossil fuel-fired steam generating units as “steam generating units” or as “utility boilers and IGCC units.” These are units whose emission of criteria pollutants are covered under 40 CFR part 60, subpart Da. Criteria pollutants are those for which the EPA issues health criteria pursuant to CAA section 108, issues national ambient air quality standards (NAAQS) pursuant to CAA section 109, promulgates area designations of attainment, nonattainment, or unclassifiable pursuant to CAA section 107, and reviews and approves or disapproves state implementation plan (SIP) submissions and issues federal implementation plans (FIPs) pursuant to CAA section 110. GHG are not criteria pollutants. The EPA also issued final standards for steam generating units that implement “large modifications,” ( i.e., modifications resulting in an increase in hourly CO 2 emissions of more than 10 percent). The standards of performance for modified steam generating units that make large modifications are based on each affected unit's own best historical performance as the BSER. The EPA did not issue final standards for steam generating units that implement “small modifications” ( i.e., modifications resulting in an increase in hourly CO 2 emissions of less than or equal to 10 percent). For steam generating units that undergo a “reconstruction” ( i.e., the replacement of components of an existing EGU to an extent that both: (1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new EGU, and (2) it is technologically and economically feasible to meet the applicable standards), 11 the EPA finalized standards based on the performance of the most efficient generating technology for these types of units as the BSER ( i.e., reconstructing the boiler as necessary to use steam with higher temperature and pressure, even if the boiler was not originally designed to do so). 12 The 2015 emission standard for large EGUs (greater than approximately 200 megawatts (MW)) was based on the performance of a well-operated PC EGU using supercritical steam conditions. The emission standard for small EGUs (less than approximately 200 MW) was based on the performance of a well-operated PC using the best available subcritical steam conditions. The difference in the standards for larger and smaller EGUs was based on the commercial availability of higher pressure/temperature steam turbines ( e.g., supercritical steam turbines) for large EGUs. While it is technically possible to design smaller supercritical steam turbines, due to the lack of commercial availability, the EPA was not able to access sufficient information regarding the cost of developing a specially designed steam turbine to determine that this was appropriate for inclusion as BSER. 11 40 CFR 60.15. 12 Steam with higher temperature and pressure has more thermal energy that can be more efficiently converted to electrical energy. The EPA has historically been notified of only a limited number of NSPS modifications involving fossil fuel-fired steam generating units. See Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units—Proposed Rule, 77 FR 22392, 22400 (April 13, 2012). Given the limited information, the Agency concluded during the 2015 rulemaking that it lacked sufficient information to establish standards of performance for all types of modifications at steam generating units. Instead, the EPA determined that it was appropriate to establish standards of performance only for affected modified steam generating units that undergo modifications resulting in an hourly increase in CO 2 emissions (mass per hour) of more than 10 percent (“large” modifications) as compared to the source's highest hourly emission during the previous 5 years. The Agency determined that it had adequate information regarding the types of large, capital-intensive projects 13 that could result in large increases in hourly CO 2 emissions. Additionally, the Agency determined that it had adequate information regarding the types of measures available to control emissions from sources that undergo such modifications, and on the costs and effectiveness of such control measures. The EPA determined that the BSER for steam generating units that trigger the large modification provision is each affected unit's own best historic annual CO 2 emission rate (from 2002 to the date of the modification). 13 Major facility upgrades involving the refurbishment or replacement of steam turbines or other equipment upgrades that could significantly increase an EGU's capacity to burn more fossil fuel, thereby resulting in a large emissions increase. With respect to affected steam generating units that undergo modifications that result in smaller increases in CO 2 emissions (specifically, steam generating units that conduct modifications resulting in an increase in hourly CO 2 emissions (mass per hour) of 10 percent or less (“small” modifications) compared to the source's highest hourly emission during the previous 5 years), the EPA concluded it did not have sufficient information and did not finalize any standard of performance or other requirements. The EPA continues to review whether it has sufficient information to establish appropriate standards for small modifications and is soliciting comment on options for determining appropriate standards in this action (Comment C-2). The 2015 Rule also finalized standards of performance for newly constructed and reconstructed stationary combustion turbine EGUs. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA finalized a standard based on efficient NGCC technology as the BSER. For newly constructed and reconstructed non-base load natural gas-fired and multi-fuel-fired (both base load and non-base load) stationary combustion turbines, the EPA finalized a heat input-based clean fuels standard. The EPA did not promulgate final standards of performance for modified stationary combustion turbines due to lack of information. The EPA received six petitions for reconsideration of the 2015 final CAA section 111(b) GHG NSPS rule. The EPA denied five of the petitions on the basis they did not satisfy one or both of the statutory conditions for reconsideration under CAA section 307(d)(7)(B), and deferred action on a petition that raised the issue of the treatment of biomass on May 6, 2016 (81 FR 27442). Multiple parties also filed petitions for judicial review of the 2015 Rule. These petitions were consolidated into a single case and the petitioners filed opening written briefs in October 2016. The EPA and supporting intervenors filed opening written briefs in December 2016. Next, petitioners submitted written reply briefs in January 2017. On April 28, 2017, the United States Court of Appeals for the District of Columbia granted the EPA's motion to hold the cases in abeyance while the Agency reviews the 2015 Rule and considers whether to propose revisions to it. D. The Purpose of This Regulatory Action Executive Order 13783 (Promoting Energy Independence and Economic Growth) directs all executive departments and agencies, including the EPA, to “immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law.” 14 Moreover, the Executive Order directs the EPA to undertake this process of review with regard to the New Source Rule issued under CAA section 111(b). 14 Id., Section 1(c). In a document signed the same day as Executive Order 13783 and published in the Federal Register at 82 FR 16330 (April 4, 2017), the EPA announced that, consistent with the Executive Order, it was initiating its review of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Generating Units, and providing notice of forthcoming proposed rulemakings consistent with the Executive Order. As explained below, that review has led the EPA to propose to revise the BSER determinations for new, reconstructed, and modified coal-fired EGUs, including reconsideration issues previously denied by the Agency. E. Does this action apply to me? Table 2 of this preamble lists the regulated industrial source categories that are the subject of this proposal. Table 2 is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that this proposed action is likely to affect. The proposed standards, once promulgated, will be directly applicable to the affected sources. To determine whether your facility, company, business, organization, etc., would be regulated by this proposed action, you should examine the applicability criteria in 40 CFR 60.1. If you have questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA Regional representative as listed in 40 CFR 60.4 (General Provisions). Table 2—Industrial Source Categories Affected by This Proposed Action Category NAICS code 1 2 Examples of regulated entities Industry 221112 Fossil fuel electric power generating units. Federal government 3 221112 Fossil fuel electric power generating units owned by the federal government. State/local government 3 221112 Fossil fuel electric power generating units owned by municipalities. Tribal government 921150 Fossil fuel electric power generating units in Indian Country. 1 North American Industry Classification System. 2 Includes NAICS codes for source categories that own and operate electric power generating units (including boilers and stationary combined cycle combustion turbines). 3 Federal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. F. Where can I get a copy of this document and other related information? In addition to being available in the docket, an electronic copy of this action is available on the internet. Following signature by the Administrator, the EPA will post a copy of this proposed action at https://www.epa.gov/stationary-sources-air-pollution/proposal-nsps-ghg-emissions-new-modified-and-reconstructed-egus. Following publication in the Federal Register , the EPA will post the Federal Register version of the proposal and key technical documents at this same website. A version of the regulatory language that incorporates the proposed changes in this action in track changes ( i.e., redline) is available in the docket for this action (Docket ID No. EPA-HQ-OAR-2013-0495). II. Proposed Requirements for New, Reconstructed, and Modified Sources A. Applicability Requirements The EPA identified the applicability requirements for the 40 CFR part 60, subpart TTTT standards in the 2015 rulemaking, and the Agency is not proposing to revise or reopening those requirements, except as noted below. Those requirements are as follows: In general, the EPA refers to fossil fuel-fired electric generating units that would be subject to a CAA section 111 emission standard as “affected” EGUs or units. An EGU is any fossil fuel-fired electric utility steam generating unit ( i.e., a utility boiler or IGCC unit) or combustion turbine (in either simple cycle or combined cycle configuration). To be considered an affected EGU under 40 CFR part 60, subpart TTTT, the unit must meet the following applicability criteria: The unit must both: (i) Be capable of combusting more than 250 million British thermal units per hour (MMBtu/h) (260 gigajoules per hourA(GJ/h)) of heat input of fossil fuel (either alone or in combination with any other fuel); 15 and (ii) serve a generator capable of supplying more than 25 MW net to a utility distribution system ( i.e., for sale to the grid). 16 However, 40 CFR part 60, subpart TTTT includes applicability exemptions for certain EGUs, including: (1) Non-fossil fuel units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of their heat input capacity on an annual basis; (2) CHP units that are subject to a federally enforceable permit limiting annual net electric sales to no more than either the unit's design efficiency multiplied by its potential electric output, or 219,000 megawatt-hours (MWh), whichever is greater; (3) stationary combustion turbines that are not physically capable of combusting natural gas ( e.g., those that are not connected to a natural gas pipeline); (4) utility boilers and IGCC units that have always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output ( e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (5) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (6) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (7) certain projects under development, as discussed below. 15 The EPA refers to the capability to combust 250 MMBtu/h of fossil fuel as the “base load rating criterion.” Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input. 16 The EPA refers to the capability to supply 25 MW net to the grid as the “total electric sales criterion.” The CAA defines a new or modified source for purposes of a given regulation as any stationary source that commences construction or modification after the publication of the proposed regulation. Thus, any standards of performance the Agency finalizes as part of this rulemaking will apply to EGUs that commence construction, reconstruction, or modification after the date of this proposal. (EGUs that commenced construction after the date of the proposal for the 2015 Rule and before the date of this proposal will remain subject to the standards of performance promulgated in that Rule.) A modification is any physical change in, or change in the method of operation of an existing source that increases the amount of any air pollutant emitted to which a standard applies. 17 The NSPS General Provisions (40 CFR part 60 subpart A) provide that an existing source is considered a new source if it undertakes a reconstruction. 18 17 40 CFR 60.2. 18 40 CFR 60.15(a). The EPA is proposing several changes to the applicability requirements. First, the EPA is proposing to change the exemption from applicability for EGUs (item 1 on the list above) on the grounds that they are considered non-fossil-fuel EGUs by revising the definition of non-fossil fuel EGUs from EGUs capable of “combusting 50 percent or more non-fossil fuel” to EGUs capable of “ deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating .” (emphasis added). This amendment is consistent with the original intent to cover only fossil fuel EGUs and would assure that solar thermal EGUs with natural gas backup burners, which are similar to other types of non-fossil fuel units in that most of their energy is derived from non-fossil fuel sources, are not subject to the requirements of 40 CFR part 60, subpart TTTT. The definition of base load rating would also be amended to include the heat input from non-combustion sources ( e.g., solar thermal). Next, the design efficiency of an EGU is used to determine the electric sales applicability threshold. 40 CFR part 60, subpart TTTT currently allows the use of three methods for determining the design efficiency. 19 To reduce compliance burden, the EPA is proposing to allow alternative methods as approved by the Administrator on a case-by-case basis. 20 The EPA is also proposing to change the applicability of paragraph 60.8(b) in Table 3 of subpart TTTT from no to yes. This amendment would allow the Administrator to approve alternatives to the test methods specified in subpart TTTT. Finally, to avoid potential double counting of electric sales, the EPA is proposing that for CHP units determining net electric sales, purchased power of the host facility would be determined based on the percentage of thermal power provided to the host facility by the specific CHP facility. If any of these amendments are not finalized, EGUs that would be exempted by the proposed amendments would remain subject to 40 CFR part 60, subpart TTTT. 19 Subpart TTTT currently lists ASME PTC 22 Gas Turbines, ASME PTC 46 Overall Plant Performance, and ISO 2314 Gas turbines—acceptance tests as approved methods to determine the design efficiency. 20 Owners/operators of EGUs would petition the Administrator is writing to use an alternate method to determine the design efficiency. Administrator discretion is intentionally left broad and could include other ASME or ISO methods as well as data to demonstrate the design efficiency of the EGU. B. Emission Standards In this action, the EPA proposes revisions to the 2015 Rule's provisions for newly constructed coal-fired electric utility steam generating units (both utility boilers and IGCC units). The EPA proposes to revise its previous determination that the BSER for such newly constructed EGUs is partial CCS. The EPA bases this revision on (1) an updated analysis of what represents reasonable costs and (2) an updated analysis of the geographic availability of CCS. In addition, the EPA solicits comment on the technical feasibility of carbon capture technologies. Instead, the EPA proposes to create three subcategories of steam generating units: Large units, defined as units with heat input greater than 2,000 MMBtu/h; small units, defined as units with heat input less than or equal to 2,000 MMBtu/h; and units of any size (that meet the applicability criteria) and that are fired with coal refuse. The EPA proposes to find that for each of these subcategories, the BSER is the most efficient demonstrated steam cycle ( i.e., supercritical steam conditions for large units and best available subcritical steam conditions for small and coal refuse-fired units) in combination with the best operating practices. Unless stated otherwise, the EPA's use of the term supercritical steam conditions, or, more simply, supercritical, encompasses both ultra-supercritical and advanced ultra-supercritical steam conditions. There is no thermodynamic definition of ultra-supercritical or advanced ultra-supercritical steam conditions; rather, they are terms used to define subsets of supercritical steam conditions with higher temperatures and pressures. 21 The EPA is proposing revised standards of performance for newly constructed steam units in the three subcategories that reflect the Agency's proposed BSER determinations: 1,900 pounds of CO 2 per MWh of gross output (lb CO 2 /MWh-gross) for large EGUs; 2,000 lb CO 2 /MWh-gross for small EGUs, and 2,200 lb CO 2 /MWh-gross for coal refuse-fired units. 22 The EPA is not proposing to revise its view in the 2015 Rule that natural gas co-firing and IGCC are alternate control technologies, but as described in section V.B of this preamble, not the BSER. The EPA invites the public to identify any additional information not considered by the Agency in the BSER analysis. (Comment C-3) 21 Supercritical, ultra-supercritical, and advanced ultra-supercritical steam generators operate at pressures greater than 22 megapascals (MPa) (3,205 pounds per square inch (psi)), temperatures greater than 550 degrees Celsius (°C) (1,022 degrees Fahrenheit (°F)), and use the same general steam generating unit design. The primary difference is that different materials are required to withstand the higher temperatures of ultra-supercritical and advanced ultra-supercritical steam conditions. 22 In contrast, in the 2015 Rule, the EPA did not create any subcategories for new steam generating units. In addition, in this action, the EPA proposes to revise the 2015 Rule's standard of performance for reconstructed EGUs to be consistent with the numeric standards for new EGUs. By the same token, with respect to modified EGUs, the EPA proposes to revise the 2015 Rule's maximally stringent emissions rate for large modifications to be the same as the standards for newly constructed and reconstructed units in the same three subcategories ( e.g., while the standard would continue to be based on looking at average historical data, the EPA is proposing that the standard can be no lower than the new source standard). While the EPA is proposing revisions to the maximally stringent emission standards, the Agency is not proposing to revise or reopening the 2015 Rule's BSER determination, which was the use of the most efficient generation available in combination with best operating practices, based on historical emissions, or the associated standard of performance. The EPA is soliciting comment on standards of performance for “small” modifications based on a unit's best demonstrated historical performance and the most appropriate approach to account for emissions variability due to changes in the mode of operation and other factors (Comment C-4). The EPA is not proposing to revise or reopening the 2015 Rule's requirement that the emission standards applicable to any type of EGU (however they may be revised in a final action on this proposal) apply at all times, including during periods of startup, shutdown, and malfunction (SSM). In addition, in this action, the EPA is not proposing to revise or reopening the air pollutants covered by the 2015 Rule or any of the Rule's continuous monitoring requirements; emissions performance testing requirements; continuous compliance requirements; or notification, recordkeeping, and reporting requirements. Furthermore, the EPA is not proposing to amend or reopening the 2015 Rule's BSER determination or standards of performance for new or reconstructed stationary combustion turbines. Table 3 below summarizes the proposed standards of performance for three proposed subcategories of newly constructed and reconstructed EGUs as well as the proposed maximally stringent standards for modified EGUs. Consistent with the 2015 rulemaking, these emission standards would apply on a 12-operating month rolling average. Table 3—Summary of BSER and Proposed Standards for Affected Sources Affected source BSER Emissions standard New and Reconstructed Steam Generating Units and IGCC Units Most efficient generating technology in combination with best operating practices 1. 1,900 lb CO 2 /MWh-gross for sources with heat input >2,000 MMBtu/h. 2. 2,000 lb CO 2 /MWh-gross for sources with heat input ≤2,000 MMBtu/h OR 3. 2,200 lb CO 2 /MWh-gross for coal refuse-fired sources. Modified Steam Generating Units and IGCC Units Best demonstrated performance A unit-specific emission limit determined by the unit's best historical annual CO 2 emission rate (from 2002 to the date of the modification); the emission limit will be no more stringent than 1. 1,900 lb CO 2 /MWh-gross for sources with heat input >2,000 MMBtu/h. 2. 2,000 lb CO 2 /MWh-gross for sources with heat input ≤2,000 MMBtu/h OR 3. 2,200 lb CO 2 /MWh-gross for coal refuse-fired sources. The EPA is proposing that the amended emission standards apply to any EGUs that commence construction, reconstruction, or modification after December 20, 2018. The EPA is not aware of any coal fuel-fired EGUs that have commenced construction, reconstruction, or modification since January 8, 2014 (the applicability date of 40 CFR part 60, subpart TTTT). Therefore, no existing units would be impacted by the proposed revised BSER determination. III. Legal Authority A. Statutory Background This action is governed by CAA section 111, which authorizes and directs the EPA to prescribe NSPS applicable to certain new stationary sources (including newly constructed, modified, and reconstructed sources). 23 As a preliminary step to regulation, the EPA lists categories of stationary sources that the Administrator, in his or her judgment, finds “cause, or contribute significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” the EPA has listed and regulated more than 60 stationary source categories under CAA section 111. 24 23 CAA section 111(b)(1)(A). 24 See generally 40 CFR part 60, subparts D-MMMM. The EPA's authority for this proposed rule is CAA section 111(b)(1). In both the 2015 Rule and the 2014 proposed rule, the EPA discussed the requirements of that provision and why the Rule met them. See 80 FR 64510, 64529-31 (2015 Rule), 79 FR 1430, 1455 (January 8, 2014) (2014 proposed rule). In summary, CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under CAA section 111. A category of sources is to be included on the list “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Once the Administrator lists a source category under CAA section 111(b)(1)(A), he or she then promulgates, under CAA section 111(b)(1)(B), “standards of performance for new sources within such category.” In the 2015 Rule, the EPA promulgated standards for CO 2 emissions from sources in two source categories, fossil fuel-fired electric utility steam generating units and combustion turbines. In the 2015 Rule, the EPA explained that the Agency interprets the statute to require an endangerment finding to be made at the time the EPA lists the source category and to broadly concern emissions from the source category, and not to concern emissions of any particular pollutant that may be made subject to a revised or newly issued standard for a source category that has already been listed. The EPA further explained that CAA section 111(b) does not specify what pollutants the EPA should regulate once it lists a source category, so that the EPA may exercise its discretion to regulate particular pollutants as long as the EPA provides a rational basis for doing so. See National Lime Ass'n v. EPA, 627 F.2d 416, 431-32 n.48 (D.C. Cir. 1980). In the 2015 Rule, the EPA described its rational basis for regulating CO 2 emissions from fossil fuel-fired EGUs, including that the CO 2 emissions from fossil fuel-fired EGUs are almost three times as much as the emissions from the next 10 source categories combined, and that the CO 2 emissions from even a single new coal-fired power plant may amount to millions of tons each year. The EPA added that even if it were required to make an endangerment finding for those emissions in order to regulate them, the same facts that provided the rational basis would qualify as an endangerment finding. 25 25 The EPA is proposing to retain the statutory interpretations and record determinations described in this paragraph. Nonetheless, the EPA is aware that various stakeholders have in the past made arguments opposing our views on these points, and the Agency sees value to allowing them to comment on these views in this rulemaking. Accordingly, the Agency will consider comments on the correctness of the EPA's interpretations and determinations and whether there are alternative interpretations that may be permissible, either as a general matter or specifically as applied to GHG emissions. For example, the Agency will consider comments on the issue of whether it is correct to interpret the “endangerment finding” as a finding that is only made once for each source category at the time that the EPA lists the source category or whether the EPA must make a new endangerment finding each time the Agency regulates an additional pollutant by an already-listed source category. Further, the EPA will consider comments on the issue of whether GHG emissions are different in salient respects from traditional emissions such that it would be appropriate to conduct a new “endangerment finding” with respect to GHG emissions from a previously listed source category. In addition, the EPA solicits comment on whether the Agency does have a rational basis for regulating CO 2 emissions from new coal-fired electric utility steam generating units and whether it would have a rational basis for declining to do so at this time, in light of, among other things, the following: (i) Ongoing and projected power sector trends that have reduced CO 2 emissions from the power sector, EIA, Annual Energy Outlook 2018 with projections to 2050 (February 6, 2018), at 102, available at https://www.eia.gov/outlooks/aeo/pdf/AEO2018.pdf, due to reduced coal-fired generation, as the EPA discusses in the proposed Affordable Clean Energy rule, 83 FR 44746, 44750-51 (August 31, 2018); and (ii) as noted above, no more than a few new coal-fired EGUs can be expected to be built, which raises questions about whether new coal-fired EGUs contribute significantly to atmospheric CO 2 levels. A “new source” is “any stationary source, the construction or modification of which is commenced after,” in general, final standards applicable to that source are promulgated or, if earlier, proposed. 26 A modification is “any physical change . . . or change in the method of operation . . . which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted” to which the standard applies. 27 The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification. 28 The EPA “may distinguish among classes, types and sizes within categories of new sources for the purpose of establishing such standards.” See CAA section 111(b)(2). 26 CAA section 111(a)(2). 27 CAA section 111(a)(4). See also 40 CFR 60.14 (concerning what constitutes a modification, how to determine the emission rate, how to determine an emission increase, and exempting specific actions that are not, by themselves, considered modifications). 28 40 CFR 60.2, 60.14(e). The NSPS General Provisions (40 CFR part 60, subpart A) provides that an existing source is considered to be a new source if it undertakes a “reconstruction,” which is the replacement of components of an existing EGU to an extent that both (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new EGU, and (2) it is technologically and economically feasible to meet the applicable standards. 29 29 40 CFR 60.15. Congress first enacted the definition of “standard of performance” as part of CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and amended it again in the 1990 CAAA to largely restore the original definition as it read in the 1970 CAAA. It is in the legislative history for the 1970 and 1977 CAAAs that Congress primarily addressed the definition as it read in those two versions of the statute, and that legislative history provides guidance in interpreting this provision. 30 In addition, the U.S. Court of Appeals for the D.C. Circuit has reviewed rulemakings under CAA section 111 on numerous occasions during the past 40 years, issuing decisions dated from 1973 to 2011, 31 through which the Court has developed a body of case law that interprets the term “standard of performance.” 30 In the 1970 CAAA, Congress defined “standard of performance,” 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 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” (emphasis added); and (ii) require a specific 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 non-air quality health and environment impact and energy requirements.” In the 1990 CAAA, Congress again revised the definition, this time repealing the requirements that the standard of performance be based on the best technological system and achieve a percentage reduction in emissions, and replacing those provisions with the terms used in the 1970 CAAA version of CAA section 111(a)(1) that the standard of performance be based on the “best system of emission reduction . . . adequately demonstrated.” This 1990 CAAA version is the current definition. Even so, because parts of the definition as it read under the 1977 CAAA were retained in the 1990 CAAA, see CAA section 111(a)(1), 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 currently. 31 Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp.; Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011). See also Delaware v. EPA, No. 13-1093 LEXIS CITE (D.C. Cir. May 1, 2015). Section 111(b) of the CAA authorizes the EPA to set “standards of performance” for new, reconstructed, and modified stationary sources from listed source categories to minimize emissions of air pollutants to the environment. Under CAA section 111(a)(1), the EPA must set these standards at the level that reflects the “best system of emission reduction . . . adequately demonstrated” taking into account technical feasibility, costs, and non-air quality health and environmental impacts and energy requirements. 32 The text and legislative history of CAA section 111, the EPA's regulatory interpretations of that provision, and relevant court decisions, identify factors for the EPA to consider in making a BSER determination. They include, among others, whether the system of emission reduction is technically feasible, whether the costs of the system are reasonable, the amount of emissions reductions the system would generate, 33 and whether the standard would effectively promote further deployment or development of advanced technology. 34 32 The standard that EPA develops, reflecting the performance of the BSER, commonly takes the form of a numeric emission limit, expressed as a numeric performance level that can either be normalized to a rate of output or input ( e.g., tons of pollution per amount of product produced—a so-called rate-based standard), or expressed as a numeric limit on mass of pollutant that may be emitted ( e.g., 100 micrograms per cubic meter (µg/m 3 )—or parts per billion). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a standard CAA section 111(b)(5) and (h). Rather, sources generally may select any measure or combination of measures that will achieve the emissions level of the standard of performance. CAA section 111(b)(5). In establishing standards of performance, EPA has significant discretion to create subcategories based on source type, class, or size. CAA section 111(b)(2); see also Lignite Energy Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999). 33 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981). 34 See id. at 347. The overall approach to determining the BSER, which incorporates the various elements, is as follows: First, the EPA identifies the “system[s] of emission reduction” that have been “adequately demonstrated” for a particular source category. Second, the EPA determines the “best” of these systems after evaluating the extent of emission reductions, costs, any non-air health and environmental impacts, and energy requirements. Third, the EPA selects an achievable standard for emissions—here, the emission rate—based on the performance of the BSER. The remainder of this subsection discusses the various elements in that analytical approach. 1. “System[s] of Emission Reduction . . . Adequately Demonstrated” The EPA's first step is to identify “system[s] of emission reduction . . . adequately demonstrated.” An “adequately demonstrated” system, according to the D.C. Circuit, is “one which has been shown to be reasonably reliable, reasonably efficient and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” 35 It does not mean that the system “must be in actual routine use somewhere.” 36 Rather, the Court has said, “[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on `crystal ball' inquiry.” 37 The EPA has previously explained that the requirement that the standard for emissions be “achievable” based on the “best system of emission reduction . . . adequately demonstrated” indicates that one of the requirements for the technology or other measures that the EPA identifies as the BSER is that the measure must be technically feasible (81 FR 64538). 35 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974). 36 Portland Cement Ass'n, 486 F.2d at 391 (citations omitted) (discussing the Senate and House bills and reports from which the language in CAA section 111 grew). 37 Id. (citations omitted). 2. “Best” In determining which adequately demonstrated system of emission reduction is the “best,” the EPA considers the following factors: a. Costs Under CAA section 111(a)(1), the EPA is required to take into account “the cost of achieving” the required emission reductions. 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 which would be “exorbitant,” 38 “greater than the industry could bear and survive,” 39 “excessive,” 40 or “unreasonable.” 41 As the EPA has explained in a prior rulemaking, for convenience, the EPA uses “reasonableness” to describe costs well within the bounds established by this jurisprudence. 38 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). 39 Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975). 40 Sierra Club v. Costle, 657 F.2d at 343 (D.C. Cir. 1981). 41 Id. The D.C. Circuit has indicated that the EPA has substantial discretion in its consideration of cost under CAA section 111(a). In several cases, the Court upheld standards that entailed significant costs, consistent with Congress's view that “the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.” 42 See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); 43 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 sulfur dioxide (SO 2 ) emissions from coal-fired power plants when the ”cost of the new controls . . . is substantial”). 44 Moreover, section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, again affording the EPA considerable discretion in choosing a means of cost consideration. 45 42 1977 House Committee Report at 184. 43 The costs for these standards were described in the rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 (March 21, 1972). 44 Indeed, in upholding the EPA's consideration of costs under the provisions of the Clean Water Act authorizing technology-based standards based on performance of a best technology taking costs into account, 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); Ass'n 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). 45 See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs). b. Non-Air Quality Health and Environmental Impacts Under CAA section 111(a)(1), the EPA is required to take into account “any non-air quality health and environmental impact” in determining the BSER. As the D.C. Circuit has explained, this requirement makes explicit that a system cannot be “best” if it does more harm than good due to cross-media environmental impacts. 46 46 Portland Cement, 486 F. 2d at 384; Sierra Club, 657 F.2d at 331; see also Essex Chemical Corp., 486 F.2d at 439 (remanding standard to consider solid waste disposal implications of the BSER determination). c. 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” entail, for example, the impact, if any, of the system of emission reduction on the source's own energy needs. d. Amount of Emissions Reductions As the EPA has previously explained, although the definition of “standard of performance” does not by its terms identify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the “best system of emission reduction,” the D.C. Circuit has stated that the EPA must in fact do so. See 81 FR at 64529; See Sierra Club v. Costle, 657 F.2d at 326. 47 47 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 to require consideration of the amount of air emissions reductions remains valid for the phrase “best system.” e. Sector or Nationwide Component of the BSER Factors The D.C. Circuit has also interpreted CAA section 111 to allow (but not require) the EPA to consider the various factors it is required to consider on a national or regional level and over time, not only on a plant-specific level or as of the time of the rulemaking. 48 49 48 Sierra Club , 657 F.2d at 327-28 (quoting 44 FR 33583/3-33584/1), 331 (citations omitted) (citing legislative history). See 81 FR at 64539; 79 FR 1430, 1466 (January 8, 2014) (explaining that although the D.C. Circuit decided Sierra Club 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)). 49 The D.C. Circuit's authorization for EPA to consider the factors on a national or regional level does not refer to the types of controls or actions that may be part of the BSER, rather, it refers to the factors EPA uses to evaluate the impacts of those controls or actions. 3. Achievability of the Standard for Emissions The definition of “standard of performance” provides that the emission limit ( i.e., the “standard for emissions”) that the EPA promulgates must be “achievable” based on performance of the BSER. See 81 FR at 64539-40 (discussing D.C. Circuit case law for requirements for achievability). 4. Expanded Use and Development of Technology The D.C. Circuit has made clear that Congress intended for CAA section 111 to create incentives for new technology, and therefore, the EPA is required to consider technological innovation as one of the factors in determining the “best system of emission reduction.” 50 50 Sierra Club, 657 F.2d at 346-47. 5. Overall Agency Discretion To Balance the Factors 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, the Court explained that “section 111(a) explicitly instructs the EPA to balance multiple concerns when promulgating a NSPS,” 51 and emphasized that “[t]he text gives the EPA broad discretion to weigh different factors in setting the standard.” 52 In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the Court reiterated: 51 Id., 657 F.2d at 319. 52 Id., 657 F.2d at 321; see also New York v. Reilly, 969 F. 2d 1147, 1150 (D.C. Cir. 1992) ( 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). 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. 53 53 Lignite Energy Council, 198 F.3d at 933. 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 the 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 decision making.”). B. Authority To Revise Existing Regulations The EPA's ability to revisit existing regulations is well-grounded in the law. Specifically, the EPA has inherent authority to reconsider, repeal, or revise past decisions to the extent permitted by law so long as the Agency provides a reasoned explanation. See Motor Vehicle Manufacturers Association of the United States v. State Farm Mutual Automobile Insurance Co., 463 US 29, 56-57 (1983) (“an agency changing its course must supply a reasoned analysis,” quoting Greater Boston Television Corp. v. FCC, 143 F.2d 841, 842 (D.C. Cir.)). The CAA complements the EPA's inherent authority to reconsider prior rulemakings by providing the Agency with broad authority to prescribe regulations as necessary. See 42 U.S.C. 7601(a). The authority to reconsider prior decisions exists in part because the EPA's interpretations of statutes it administers “[are not] instantly carved in stone,” but must be evaluated “on a continuing basis.” Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64 (1984). This is true, as is the case here, when review is undertaken “in response to . . . a change in administrations.” National Cable & Telecommunications Ass'n v. Brand X Internet Services, 545 U.S. 967, 981 (2005). Indeed, “[a]gencies obviously have broad discretion to reconsider a regulation at any time.” Clean Air Council v. Pruitt, 862 F.3d 1, 8-9 (D.C. Cir. 2017). C. Authority To Regulate CO 2 From Fossil Fuel-Fired EGUs The EPA's authority for this proposed rule is CAA section 111(b)(1). In the 2015 Rule, the EPA discussed the requirements of that provision and why the Rule met them (80 FR 64529-31). The EPA summarizes that discussion here, but is not re-opening any of the issues discussed: CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under section 111. A category of sources is to be included on the list “if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Once the Administrator lists a source category under section 111(b)(1)(A), the Administrator then promulgates, under section 111(b)(1)(B), “standards of performance for new sources within such that category.” In the 2015 Rule, the EPA promulgated standards for CO 2 emissions from sources in two source categories, fossil fuel-fired electric utility steam generating units and combustion turbines. The EPA explained that because it was not listing a new source category, it was not required to make a new endangerment finding with regard to the affected sources, and the EPA added that in any event, the required endangerment finding concerned the source category, and not individual pollutants. The EPA further explained that section 111(b) does not specify what pollutants the EPA should regulate once it lists a source category, so that the EPA may exercise its discretion to regulate particular pollutants as long as the EPA provides a rational basis for doing so. In the 2015 Rule, the EPA described its rational basis for regulating CO 2 emissions from fossil fuel-fired EGUs. The EPA added that even if it were required to make an endangerment finding for those emissions in order to regulate them, the same facts that provided the rational basis would qualify as an endangerment finding. IV. Rationale for Proposed Applicability Criteria The current non-fossil applicability exemption is based strictly on the combustion of non-fossil fuels ( e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU must be both (1) capable of combusting over 50 percent non-fossil fuel and (2) limit the use of all fossil fuels to an annual capacity factor of 10 percent or less. The current language does not take heat input from non-combustion sources ( e.g., solar thermal) into account. Certain solar thermal installations have natural gas backup burners that are over 250 MMBtu/h. As currently written, these solar thermal installations would not be eligible to be considered non- fossil units since they are not capable of deriving more than 50 percent of the heat input from the combustion of non-fossil fuels. Therefore, solar thermal installations that include backup burners could meet the applicability criteria of 40 CFR part 60, subpart TTTT even if the burners are limited to an annual capacity factor of 10 percent or less. Amending the applicability language to include heat input derived from non-combustion sources would allow these facilities to avoid applicability with 40 CFR part 60, subpart TTTT by limiting the use of the natural gas burners to less than 10 percent of the capacity factor of the backup burners. These EGUs would readily comply with the emissions standard, but the reporting and recordkeeping would increase costs for these EGUs. The proposed amended non-fossil applicability language of changing “combusting” to “deriving” will assure that 40 CFR part 60, subpart TTTT continues to cover the fossil fuel-fired EGUs, properly understood, that it was intended to cover, while minimizing unnecessary costs to EGUs fueled primarily by renewable energy. The corresponding change in the base load rating to include the heat input from non-combustion sources is necessary to determine the relative heat input from fossil and non-fossil sources. The definition of design efficiency ( i.e., the efficiency of converting thermal energy to useful energy output) is used to determine if an EGU meets the electric sales criteria and is relevant to both new and existing EGUs. EGUs that sell less electricity than the electric sales criteria are not included in the applicability of subpart TTTT. The sales criteria is based in part of the individual EGU design efficiency. The current definition includes several specific options for determining the design efficiency. Since the 2015 final rule, the EPA has become aware that owners/operators of certain existing units do not have records of the original design efficiency. These units are therefore not able to readily determine if they meet the applicability criteria and are subject to the existing source 111(d) requirements. Many of these units are CHP units and it is highly likely they do not meet the applicability criteria. However, the current language would require them to conduct additional testing to demonstrate this. To minimize the compliance burden and to provide additional flexibility to the regulated community, the proposed amendment to the definition of design efficiency would allow the Administrator to approve alternate test methods to determine the design efficiency. For existing CHP units with large useful thermal outputs that would clearly not meet the electric sales applicability criteria, this could potentially include the use of historical operating data. For CHP units, the current approach for determining net electric sales for applicability purposes allows the owner/operator to subtract the purchased power of the thermal host facility. The intent of the approach is to determine applicability similarly for third-party developers and CHP units owned by the thermal host facility. 54 However, as currently written, each third-party CHP unit would subtract the entire electricity use of the thermal host facility when determining its net electric sales. It is clearly not the intent of the provision to allow multiple third-party developers that serve the same thermal host to all subtract the purchased power of the thermal host facility when determining net electric sales. This would result in counting the purchased power multiple times. In addition, it is not the intent of the provision to allow a CHP developer to provide a trivial amount of useful thermal output to multiple thermal hosts and then subtract all of the thermal hosts' purchased power when determining net electric sales for applicability purposes. The proposed amendment would set a limit to the amount of thermal host purchased power that a third-party CHP developer can subtract for electric sales when determining net electric sales equivalent to the percentage of useful thermal output provided to the host facility by the specific CHP unit. This approach would eliminate both circumvention of the intended applicability by sales of trivial amounts of useful thermal output and double counting of thermal host-purchased power. 54 For contractual reasons, many developers of CHP units sell all the generated electricity to the electricity distribution grid even though in actuality a significant portion of the generated electricity is used onsite. Owners/operators of both the CHP unit and thermal host can subtract the site purchased power when determining net electric sales. Third party developers that do not own the thermal host can also subtract the purchased power of the thermal host when determining net electric sales for applicability purposes. Finally, during the 2015 rulemaking, the EPA identified the Washington County (GA) and Holcomb (KS) EGU projects as “projects under development” that would not be able to meet the standard of performance without a complete redesign (80 FR 64542-43). As a result, the EPA determined that it would not be appropriate to apply the standard to those projects and excluded them. The EPA added that if it received information suggesting that either will be built, the Agency would propose a standard of performance specifically for the project. It is not clear if these projects will be constructed, and, if so, whether they would be able to meet the standard proposed in this action. For this reason, the EPA is not proposing to amend the manner in which the 2015 Rule addressed these projects. Thus, the proposed standard would not apply to these projects, and if the Agency receives information suggesting that either will be built, the EPA will propose a standard of performance specifically for the project. However, the EPA also requests comment on whether the projects should be covered by the standard proposed in this action (Comment C-5) V. Rationale for Proposed Emission Standards for New and Reconstructed Fossil Fuel-Fired Steam Generating Units In the 2015 Rule, the EPA determined that partial CCS was the BSER for newly constructed coal-fired steam generating units. The EPA determined that partial CCS had reasonable costs (the levelized cost of electricity (LCOE) was comparable to the costs of two then-current projects to add nuclear capacity, and the percentage increase in capital costs was comparable to increases that the industry had shown it could absorb), 55 was technically feasible in the majority of the U.S., achieved meaningful emission reductions, and promoted technology development. For the reasons discussed immediately below, on the basis of updated information, the EPA proposes that partial CCS does not qualify as the BSER; and for the reasons discussed further below, the EPA proposes that highly efficient generation technology is the BSER. 55 The two projects are SCE&G and Santee Cooper's V.C. Summer Nuclear Generating Station and Georgia Power and Southern Company's Vogtle Electric Generating Station. A. Review of the 2015 BSER Analysis 1. Review of Reasonable Cost Criteria In the 2015 Rule, as part of the partial CCS BSER determination, the EPA evaluated the costs for new base load electricity generating options to determine what was a “reasonable” cost. Specifically, the EPA determined that the LCOE for a new non-natural gas fossil fuel-fired power plant would be “reasonable” if it was consistent with the LCOE associated with the construction of a new nuclear power plant. The EPA argued that the increased costs (relative to a newly constructed natural gas combined cycle EGU) were reasonable because utilities had indicated to the EPA that they valued the fuel diversity provided by coal-fired EGUs (80 FR 64510). The EPA also determined that an increase in the capital cost of slightly more than 20 percent was reasonable when compared to previous CAA rulemakings affecting the power sector (80 FR 64560). Since 2015, additional facts have come to light that have led the EPA to reassess these determinations and therefore to reassess the reasonableness of the cost of partial CCS. Projections in 2015 from the EPA, EIA, and utility planners consistently showed NGCC as the lowest cost option for new intermediate and base load generation. Consistent with the 2015 Rule, current utility forecast models continue to project that few, if any, new coal-fired power plants will be built in the U.S. in the subsequent decade. 56 However, these models do not necessarily account for certain source-specific considerations that power plant developers use to determine what type of generation technology to construct. The EPA explained in the 2015 Rule that it was possible that circumstances would arise under which a developer would find it advantageous to build a new coal-fired EGU, for example, for purposes of fuel diversification (80 FR 64513), and the EPA has not received information since the 2015 Rule that would cause it to rule out that possibility. In the event a new coal-fired EGU is constructed in the U.S., in the absence of the requirements of 40 CFR part 60, subpart TTTT, as finalized in 2015, the EPA believes that the majority of large coal-fired EGUs would adopt the use of supercritical steam conditions and the majority of small coal-fired EGUs would use the best available subcritical steam conditions. This is consistent with the analysis included in the 2015 final rule. 56 Power sector modeling does not predict the construction of any new coal-fired EGUs. Therefore, based on modeled impacts, any GHG requirements for new coal-fired EGUs would have no significant costs or benefits. In addition, as part of the 2015 rulemaking the EPA received public comments stating that there is value in maintaining the ability to develop non-natural gas-fired base load generation that is not captured in economic dispatch models (80 FR 64559). These values can include, but are not limited to: Historically stable fuel prices; fuel security ( i.e., the ability to store significant quantities of fuel onsite), and site-specific jobs and economic development considerations ( e.g., local mining and power plant jobs, maintaining an active rail line, maintaining the property tax base, and, in the case of coal refuse, remediation of existing environmental concerns). The EPA also noted that a number of integrated resource plans (IRPs) 57 recognize significant value in these fuel diversity considerations (80 FR 64526, 64563). Several utilities included nuclear and coal-fired options in their resource plans expressly to preserve fuel diversity within their portfolios. 58 These utility sector plans justified “prudent” costs (that were significantly higher than the projected least cost option) to maintain fuel diversity. Based on these factors, in the 2015 rulemaking, the EPA developed metrics for determining reasonable costs, i.e., a cost level for performance standards at which new coal-fired EGUs can still be part of the future fuel diversity mix. These cost indicators were (1) the LCOE of other options for new non-natural gas-fired base load generation ( e.g., nuclear) and (2) the percentage increase in capital cost. 57 An Integrated Resource Plan (IRP) is a publicly available long-term resource plan outlining a utility's resource needs, considering both supply and demand side resources, to meet future energy demands reliably and cost effectively. 58 U.S. EPA, Technical Support Document: Review of Electric Utility Integrated Resource Plans, July 31, 2015, available in the rulemaking docket at https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11775. a. Levelized Cost of Electricity (LCOE) Comparison (1) Background As part of the 2015 rulemaking, the EPA assumed that developers valued fuel diversity and were therefore willing to pay a premium for non-natural gas-fired dispatchable base load generation. The EPA concluded that the LCOE of new nuclear (and biomass) generation was one appropriate indicator of the value of maintaining the option to develop new non-natural gas-fired base load generation. For this metric, the EPA used cost data from EIA 59 and U.S. Department of Energy National Energy Technology Laboratory (DOE/NETL) 60 to project the cost at which a new coal-fired EGU with partial CCS would have substantially similar levelized cost compared to new nuclear capacity. Table 4 includes the summary table of the EPA's cost projections from the preamble to the 2015 final rule ( See 80 FR 64562, Table 8). The data in Table 4 reflect the EPA's 2015 determination that the cost of full carbon capture was not reasonable. 61 However, the EPA further determined that the cost of the specified partial CCS level in Table 4 was reasonable because they were comparable to the costs of new nuclear capacity. The increase in the LCOE from a supercritical pulverized coal unit due to partial CCS ranged from approximately 20 to 30 percent. 59 EIA, Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015. June 2015. Available at https://www.eia.gov/outlooks/archive/aeo15/pdf/electricity_generation.pdf. 60 U.S. DOE NETL, Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Plants, DOE/NETL-2015/1720, June 22, 2015, available at https://www.netl.doe.gov/energy-analyses/temp/SupplementSensitivitytoCO2CaptureRateinCoalFiredPowerPlants_062215.pdf. 61 A further indication of the unfavorable economics of full capture CCS may be found in the recent cancellation by the Canadian firm, SaskPower of its planned CCS retrofits at additional units at the Boundary Dam facility, in Saskatchewan, Canada, due to high costs. See C. Marshall, “Landmark project puts coal expansion on ice,” Greenwire, July 10, 2016 (subscription required). Table 4—Predicted Cost and CO 2 Emission Levels for a Range of Potential New Generation Technologies From the 2015 Rule Technology Emissions (lb CO 2 /MWh-gross) LCOE* ($/MWh) SCPC—no CCS (bit) 1,620 76-95 SCPC—no CCS (low rank) 1,740 75-94 SCPC + ~16% CCS (bit) 1,400 92-117 SCPC + ~ 25% CCS (low rank) 1,400 95-121 Nuclear (EIA) 0 87-115 Nuclear (Lazard) 0 92-132 Biomass (EIA) 94-113 Biomass (Lazard) 87-116 IGCC 1,430 94-120 NGCC 1,000 ** 52-86 * The emissions and LCOE (2011 $) for the SCPC cases, IGCC, and NGCC are based on the NETL “Sensitivity to CO 2 Capture Rate” report. The nuclear and biomass LCOE (2011 $) are based on data from EIA and Lazard. The LCOE ranges include an uncertainty of −15%/+30% on capital costs for SCPC and IGCC cases and an uncertainty of −10%/+30% on capital costs for nuclear and biomass cases. LCOE estimates displayed in this table for SCPC units with partial CCS as well as for IGCC units use a higher financing cost rate in comparison to the SCPC unit without capture. ** This range represents a natural gas price from $5/MMBtu to $10/MMBtu. (2) Comparison With Biomass-Fired Power Plants While the EPA included biomass in the 2015 rulemaking LCOE analysis, the EPA noted that new nuclear power, which, besides natural gas combustion turbines, is the principal other option often considered for providing new base load power (79 FR 1477). Biomass-fired EGUs are smaller in scale 62 and not as closely analogous to coal-fired generation as is nuclear power. EIA projects that average net additional biomass generation capacity amounts to less than 100 MW annually. The largest domestic biomass-fired EGU is less than 200 MW and the largest international biomass-fired EGUs are less than 300 MW. Similar to coal refuse-fired EGUs, biomass-fired EGUs are limited geographically because they tend to be located in areas with large quantities of biomass that can be cost effectively delivered to the plant. Based on these considerations, the EPA does not consider biomass to be an appropriate comparison for coal-fired generation. 62 Biomass-fired EGUs tend to have challenges in securing and transporting large amounts of biomass. (3) Comparison With Nuclear-Fueled Power Plants (a) Levelized Cost of Electricity (LCOE) In the 2015 analysis, the EPA assumed nuclear generation and coal-fired generation were similarly attractive for purposes of fuel diversity. As part of this review, the EPA is reevaluating whether that assumption is valid. Specifically, the EPA is requesting comment on whether nuclear capacity is more attractive than coal as an option for providing fuel diversity (Comment C-6). Nuclear projects have no emissions of criteria pollutants, hazardous air pollutants (HAPs), 63 or GHGs. Particularly in light of potential future costs associated with GHG emissions, nuclear projects provide a significant price stability guarantee. In addition, the incremental generating costs for nuclear projects are lower than those for coal-fired EGUs, thus, nuclear EGUs would be expected to dispatch more frequently and provide more actual non-natural gas generation per amount of installed capacity. 64 Therefore, to the extent that nuclear projects are more attractive than coal-fired EGUs for providing fuel diversity, developers could be willing to pay more of a premium for nuclear projects than for coal-fired EGUs. 63 HAP are toxic air pollutants regulated under CAA section 112. 64 EIA used a 90 percent capacity factor for nuclear when calculating the LCOE in the 2015 Rule. According to EIA, the average nuclear EGU capacity factors was 92 percent in 2017. On the other hand, more recent information, since the 2015 Rule, indicates that the LCOE of a new nuclear EGU is in fact higher than what developers may be willing to accept. In 2015, multiple new advanced Generation III+ nuclear units were under construction in the U.S. 65 66 including, at that time, two new units each at the Summer and Vogtle nuclear power plants in South Carolina and Georgia, respectively. However, since the 2015 Rule, both the Summer and Vogtle projects have experienced significant delays and cost overruns. South Carolina Electric and Gas (SCE&G), majority owner of Summer, has now abandoned completion of both reactors and has raised rates at least nine times to cover the increasing costs of the reactors. 67 While over budget and behind schedule, construction of both the Vogtle units continues. They are scheduled to be completed in 2021 and 2022. Furthermore, there appear to be no new nuclear projects under construction or that have received regulatory approval at this time. According to EIA, which reports data on recently constructed EGUs and planned EGU additions, including EGUs under construction, EGUs that have received regulatory approvals but that have not commenced construction, and planned projects that have not received regulatory approvals, the only planned nuclear project is the Utah Associated Municipal Power Systems (UAMPS) Carbon Free Power Project. This project proposes to use small modular nuclear reactors developed with funding from the DOE. However, this project has not yet received all of the required regulatory approvals to proceed. The EPA solicits comment on the extent to which new nuclear energy projects can serve as a comparison point, for purposes of fuel diversity, for new coal-fired EGUs (Comment C-7). 65 EIA, Form EIA-860 Detailed Data, 2014, available at https://www.eia.gov/electricity/data/eia860/,3_1_Generator_Y2014.xls, “Proposed” sheet. 66 As of the promulgation of the 2015 Rule, 4,400 MW of new nuclear capacity was under construction with 2019-20 commercial operating dates. 67 G. Blade, “Santee Cooper, SCANA abandon Summer nuclear plant construction,” Utility Dive, July 31, 2017, available at https://www.utilitydive.com/news/santee-cooper-scana-abandon-summer-nuclear-plant-construction/448262/. In the 2015 Rule, the partial CCS costs were based largely on the report, “Cost and Performance Baseline for Fossil Energy Plants Supplement: Sensitivity to CO 2 Capture Rate in Coal-Fired Power Plants,” June 22, 2015 (DOE/NETL-2015/1720). The EPA used the reported costs without any significant adjustments. In this rulemaking, the EPA is proposing to make refinements to the CO 2 transmission and storage (T&S) costs and EGU capacity factors. That is, as described below, the EPA is proposing to adjust the T&S costs based on the amount of CO 2 captured and adjust the capacity factor based on the increase in variable operating costs due to the impact of partial CCS. Accounting for these factors revises the LCOE with partial CCS upwards. The EPA also proposes in the alternative to use the NETL costs without any significant adjustments, similar to the approach used in the 2015 Rule. The EPA is not aware of any more recent, detailed, or transparent costing analysis specific to coal-fired EGUs with or without carbon capture technology. The EPA invites the public to identify any additional costing information. First, the CO 2 T&S costs in the NETL baseline reports are not included in the reported capital cost or operation and maintenance (O&M) costs but are treated separately and added to the LCOE. Specifically, the combined transport and storage costs for geologic storage (not accounting for any revenues from the sale of CO 2 ) equaled $11 per metric ton of captured CO 2 . This cost represents annual transportation through a 100-kilometer (km) (62 mile) CO 2 pipeline and storage in a deep saline formation in the Midwest of 3.2 million tons of CO 2 . 68 The EPA used this value in all the partial capture cases as well. In this rule, to account for economies of scale, the EPA is proposing to adjust the T&S costs based on the amount of CO 2 captured. To estimate the T&S costs, the EPA is using the FE/NETL CO 2 Transport Cost Model and the FE/NETL CO 2 Saline Storage Cost Model with the same general assumptions described in “Performance Baseline for Fossil Energy Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3,” July 6, 2015 (DOE/NETL-2015/1723) and adjusting the metric megatons of CO 2 transported and stored. 69 Table 5 shows the resulting total estimated T&S costs for various amounts of captured CO 2 . 68 Use of the T&S costs for the Illinois Basin ( i.e., Midwest) are consistent with the NETL costing approach. According to NETL, T&S costs would be similar for the East Texas Basin. However, T&S costs for the Williston Basin are estimated to be 40 percent higher, and T&S costs for the Power River Basin are approximately double. 69 For additional detail on CO 2 T&S costing see section 2.7.3 CO 2 Transport and Storage in volume 1a, revision 3 of the NETL baseline reports and the T&S technical support document that is available in the docket. Table 5—CO 2 Transport and Storage Costs for Various Amounts of Capture Megatonne (Mt)/yr Total T&S cost (2016 $/tonne) 4.2 9.6 3.2 11 2.6 12 2.0 13 1.4 16 0.62 29 The EPA is using the best fit trendline to estimate the T&S costs for various amounts of CO 2 capture. The trendline predicts that costs would increase substantially at lower levels of capture. As stated previously, the EPA also proposes in the alternative to use an $11 metric ton T&S costs consistent with the NETL costing approach and the 2015 Rule. Second, as part of the 2015 rulemaking, for the LCOE calculations, consistent with the NETL calculations, as noted above, the EPA assumed a constant capacity factor 70 ( i.e., electric sales) regardless of the amount of CCS installed on the representative ( i.e., model) coal-fired EGU. This simplified approach captured the fixed and operating costs of CCS but did not account for the impact of economic dispatch ( e.g., it did not include analysis of the interaction of the affected EGU with the grid or other EGUs on an hourly basis) and loss of potential revenue due to lower electric sales. 70 EPA used an 85 percent capacity factor, consistent with the NETL LCOE calculations. However, electricity is a unique commodity in that it cannot (at present) be stored at a large scale at a reasonable cost. Therefore, electric grid operators need to make plans and take actions to match supply and demand in real time. Multiple factors influence which EGUs supply power to the grid to satisfy system load ( e.g., transmission and operational constraints) at any given point, and in which order. In the simplest terms, economic dispatch is used to satisfy the grid load at minimal costs. In the economic dispatch model, EGUs with the lowest marginal ( i.e., operating) costs are dispatched first. Those EGUs increase output until all the load is satisfied or until the EGUs cannot supply additional power. If needed, EGUs with higher operating costs are then dispatched to satisfy demand. The process continues by dispatching more expensive units until the grid load is satisfied. The marginal cost of the final generator needed to meet load sets the system marginal cost. Owners and operators of generators are paid based on the system marginal cost. Therefore, net revenue is the difference between the variable operating costs and the system marginal cost. Importantly, economic dispatch only accounts for the costs directly associated with power plant operations and does not consider any fixed costs. This is important because historically units with high fixed costs ( e.g., coal-fired and nuclear EGUs) have low operating costs, dispatch often, and typically run as base load units. For example, nuclear units tend to have operating costs on the order of $15 to $20 per MWh and capacity factors of greater than 90 percent. These units would be able to recover their high fixed costs by spreading them out over many MWh of electric sales. Units with low fixed costs but high operating costs ( e.g., simple cycle combustion turbines) have historically tended to dispatch last and provide peaking power. With natural gas prices of $4 per MMBtu, the operating costs of simple cycle units are approximately $40 per MWh and capacity factors are less than 10 percent in most cases. Therefore, an increase in operating costs of $20 per MWh can change an EGU from a high capacity factor base load unit to a peaking unit with limited operation. Emission control equipment can impact both the fixed costs and operating costs of an EGU. Another important aspect of economic dispatch, which may be unique to the electricity generation sector, is that the end user ( i.e., consumer) has historically had limited, if any, choice in what technology is used to generate electricity. Therefore, electric generators compete strictly on the basis of their variable costs, with no ability to differentiate their product. In deregulated markets, a new coal-fired EGU must compete directly against all other forms of generation, including existing coal-fired EGUs and natural gas-fired combined cycle units. A developer of a new coal-fired EGU could anticipate revenues from capacity payments, various ancillary services, and to the extent the new unit is dispatched, energy payments. In a deregulated market, each of these revenue streams is priced through competitive market-based structures. As described earlier, revenue from energy payments will largely be determined based on variable operating costs. Any requirements that impact variable operating costs could impact the ability of the owner/operator of a new coal-fired EGU to obtain adequate revenues to cover the generation investment and recover costs. In the 2015 Rule, commenters indicated that competitive electricity markets only allow for the entry of competitively-priced power. Therefore, a new coal plant with partial CCS that was compliant with an NSPS requirement based on the use of CCS might not be competitive compared to older coal plants with no CCS requirements (even if the older plants are less thermally efficient). The EPA responded that, given current and projected market conditions, any new coal-fired EGU would likely only be built in a location where it would be expected to operate at a high capacity factor ( e.g., as a base load unit). However, at least in deregulated markets, economic dispatch is still a factor for base load units and can change annual capacity factors by multiple percentage points. Moreover, an increasing number of coal-fired power plants are changing from base load to variable load. Accordingly, the EPA is proposing to include the impact of economic dispatch in determining the costs of a potential new coal-fired EGU. Inclusion of these costs is a more refined representation of the impact of the BSER determination. As stated previously, the EPA is proposing in the alternative that the Agency not account for economic dispatch and instead use the same capacity factors regardless of variable operating costs, for the same reasons as the EPA stated in the 2015 Rule. 71 71 One approach developers could take to reduce the impact on the capacity factor could be to construct a smaller EGU. While this would not impact capacity factors strictly based on simplified economic dispatch ( i.e., at the same variable operating costs the unit would still dispatch after units with lower variable operating costs) multiple factors impact dispatch and a smaller unit might provide local grid support that would allow it to operate at higher capacity factors. To estimate the impacts at a national level of the increase in variable operating costs due to partial CCS, the EPA analyzed the dispatch of coal-fired EGUs relative to variable operating costs. 72 Based on a review of the variable operating costs and capacity factors in the Annual Energy Outlook 2018 and fuel prices reported under EIA form 923, the EPA determined that capacity factors for coal-fired EGUs decrease approximately 1.5 percent for each $1/MWh increase in operating costs. Table 6 shows the operating costs of various generating technologies. The capacity factors for coal-fired EGUs have been adjusted based on a baseline of the relevant coal rank supercritical EGU having a capacity factor of 85 percent. 72 Fuel costs comprise approximately two-thirds to three-fourths of the variable operating costs for a coal-fired EGU. Table 6—Proposed T&S Costs and Capacity Factors * Technology Captured CO 2 (Mt) T&S costs ($/tonne) Variable operating costs ($/MWh) Amended CF (percent) Subcritical PC (bit) 32.3 83.5 Supercritical PC (bit) 31.3 85.0 SCPC + ~16% CCS (bit) 520,000 30 36.9 76.6 Supercritical PC (low rank) 28.0 85.0 Ultra-supercritical PC (low rank) 27.4 85.8 SCPC + ~ 26% CCS (low rank) 1,000,000 20 36.3 72.5 Combined Cycle CT (NG) 33.1 Simple Cycle CT (NG) 50.7 * Variable operating costs calculated using $2.61/MMBtu for bituminous coal, $2.09/MMBtu for low rank coal, and $4.73/MMBtu for natural gas. Captured CO 2 based on an 85 percent capacity factor. Costs are in 2016 $. Variable operating costs is also referred to as incremental generating costs. Simple cycle CT variable operating costs were estimated by adjusting the combined cycle efficiency to 33 percent. The variable operating costs shown in Table 6 demonstrate part of the reason why the U.S. generation mix is changing so dramatically with the decrease in the price of natural gas. Fuel costs comprise approximately two thirds to three quarters, depending on the coal type, of the variable operating costs for coal-fired EGUs. In comparison, fuel costs comprise over 90 percent of the variable operating costs for combined cycle EGUs. Therefore, declining natural gas prices can have a dramatic impact on the competitiveness of natural gas-fired EGUs relative to coal-fired EGUs. While the variable operating costs in Table 6 are based on long term projections for the price of natural gas, spot process can be significantly lower. When natural gas is available at $4/MMBtu or less, the variable operating costs of combined cycle units can drop below those of certain coal-fired EGUs and displace those units in the dispatch order. The data further show that due to the relatively high operating costs of CCS compared to other environmental controls, 73 a BSER based on partial CCS increases the variable operating costs of new coal plants to significantly greater than existing coal-fired EGUs without GHG controls. Therefore, in an economic dispatch system, a new coal-fired EGU with partial CCS would dispatch after the majority of existing coal-fired EGUs. 74 In markets with significant quantities of coal-fired generation, this could have a significant impact on the economic viability of a new coal-fired EGU. Table 7 shows the LCOE at an 85 percent capacity factor and $11/tonne T&S costs compared to an LCOE using the amended T&S costs (based on the amount of CO 2 captured) and using an adjusted capacity factor (based on the variable operating costs). The revised LCOE numbers account for both the amended approach to calculating T&S costs and the change in capacity factor. 73 The EPA notes that unlike other environmental controls, there is limited regulatory requirements or incentive to reduce GHG emissions aside from the NSPS requirements. For example, local or regional programs could require reductions in criteria pollutant from all EGUs and/or owners/operators of EGUs can accrue regulatory benefits in other regulatory programs due to criteria pollutant reductions ( e.g., offsets and emission credits). These programs minimize the impact of the environmental controls on dispatch because costs are spread more evenly to the entire EGU fleet. 74 This could create a perverse environmental incentive to operate existing coal more than it otherwise would. A utility-system dispatch model would be required to estimate the potential overall environmental impacts. Table 7—Predicted Cost and CO 2 Emission Levels for a Range of Potential New Generation Technologies Technology LCOE * ($/MWh) Amended LCOE ** ($/MWh) Subcritical PC (bit) 81.2 82.1 Supercritical PC (bit) 81.7 81.7 SCPC + ~16% CCS (bit) 96.2 105.4 Supercritical PC (low rank) 85.2 85.2 Ultra-supercritical PC (low rank) 87.6 87.0 SCPC + ~ 26% CCS (low rank) 109.0 122.8 * 85 percent capacity factor and $11/tonne T&S. ** Capacity factor adjusted based on variable operating costs and T&S costs adjusted based on amount of captured CO 2 . Assuming a constant 85 percent capacity factor and $11/tonne T&S costs, the LCOE for a bituminous-fired SCPC with partial CCS is 18 percent higher than a SCPC without CCS. However, when the refined T&S and capacity factors are accounted for, the relative increase in LCOE for a bituminous-fired SCPC with partial CCS is 29 percent higher than SCPC without CCS, a 63 percent increase in the relative LCOE impact of partial CCS. These costs do not account for any of the potential benefits of reduced criteria and GHG emissions due to the use of partial CCS. The EPA solicits comment on if these should be factored into the analysis, and if so, appropriate metrics to accounting for these benefits (Comment C-8). Furthermore, the revised LCOE costs are over 10 percent higher than the nuclear cost metric. Furthermore, even with only the T&S adjustment, the revised LCOE are five percent higher than the nuclear metric. The results of this analysis support the EPA's proposal to revise the 2015 determination that partial CCS is BSER for coal-fired EGUs. The EPA notes that these costs are for coal-fired EGUs that are using geologic sequestration (GS) and do not account for any specific economic incentives ( e.g., the federal tax credits for carbon capture, which are available only for new facilities that commence construction before January 1, 2024, Internal Revenue Code §§ 45Q(a)(3)-(4), (d)—which, in turn, is before the end of the 8-year period in which the EPA is required to review and, if necessary, revise the standard of performance that is the subject of this rulemaking, CAA section 111(b)(1)(B)). If the owner/operator were in a location where it could sell the byproduct CO 2 ( e.g., for enhanced oil recovery or for use in the food industry) variable operating costs could be reduced relative to an EGU without partial CCS and electric sales would be expected to increase, offsetting some of the control costs. For example, as discussed in the 2015 Rule, two coal-fired EGUs elected to install carbon capture technology and sold the CO 2 to the food industry without any federal funding for the capture technology (80 FR 64550). This type of utilization of CO 2 has the potential to both develop capture technologies and increase economic options to reduce emissions. While sale of the captured CO 2 improves the overall economics of a new coal-fired EGUs, the EPA recognizes that there are places where opportunities to sell captured CO 2 for utilization may not be presently available. Therefore, consistent with approach adopted in the 2015 Rule, the EPA is assuming no revenues from the sale of captured CO 2 (80 FR 64572). (b) Consideration of Capital Cost Increases In the 2015 rulemaking, commenters from industry recommended that the EPA should separately consider the significant capital costs of partial CCS. In response to these comments, the EPA evaluated the impact of 2015 GHG standards on the capital costs of new fossil-steam generation and compared the same to the capital costs of prior EPA regulations. The EPA determined that the incremental capital costs of partial CCS were reasonable because they were comparable to the percentage capital costs increase in prior regulations and because the utility industry has demonstrated the capacity to successfully absorb capital costs of this magnitude in the past (80 FR 64559). Specifically, in the 2015 final rule, the EPA concluded that an increase of 21 to 22 percent for capital coats was reasonable (80 FR 64560). The EPA cited several comparable rulemakings. First, the 1971 NSPS for coal-fired EGUs increased costs by $19 million (M) for a 600 MW plant. These costs consisted of $3.6 M for particulate matter (PM) controls, $14.4 M for SO 2 controls, and $1 M for nitrogen oxide (NO X ) controls; the capital cost of air pollution control devices added 15.8 percent to the $120 M capital cost of a new EGU. In that case, the baseline cost was primarily for a coal-fired EGU with limited environmental controls. In addition, a retrospective Congressional Budget Office (CBO) study of the 1978 EGU NSPS amendments estimated that those amendments increased the capital costs for a new EGU by 10 to 20 percent. There, the baseline costs and overall absolute costs were higher than the 1971 NSPS because they included the cost of controls required by the 1971 NSPS. Since the 1978 NSPS, additional environmental controls have further increased the baseline costs to construct a new coal-fired EGU. These additional costs include, but are not limited to, NSPS amendments that established selective catalytic reduction (SCR) as the BSER for NO X controls in place of low NO X combustion controls and more stringent SO 2 and PM standards, rulemakings that require mercury (Hg) controls, and rulemakings that limit the use of once-through cooling. All of these additional environmental control requirements increase the baseline costs of constructing a new coal-fired EGU. Therefore, at the same percentage increase in capital costs, absolute costs are much higher. A comparable analysis would require that the additional control costs due to previous rulemaking [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2018-27052. Public record. Not legal advice.