# Emission Guidelines for Greenhouse Gas Emissions From Existing Electric Utility Generating Units; Revisions to Emission Guideline Implementing Regulations; Revisions to New Source Review Program > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2018-18755 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** August 31, 2018 - **Citation:** 83 FR 44746 ## Text ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 51, 52, and 60 [EPA-HQ-OAR-2017-0355; FRL-9982-89-OAR] RIN 2060-AT67 Emission Guidelines for Greenhouse Gas Emissions From Existing Electric Utility Generating Units; Revisions to Emission Guideline Implementing Regulations; Revisions to New Source Review Program AGENCY: Environmental Protection Agency (EPA). ACTION: Proposed rule. SUMMARY: The Environmental Protection Agency (EPA) is proposing three distinct actions, including Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units (EGUs). First, EPA is proposing to replace the Clean Power Plan (CPP) with revised emissions guidelines (the Affordable Clean Energy (ACE) rule) that inform the development, submittal, and implementation of state plans to reduce greenhouse gas (GHG) emission from certain EGUs. In the proposed emissions guidelines, consistent with the interpretation described in the proposed repeal of the CPP, the Agency is proposing to determine that heat rate improvement (HRI) measures are the best system of emission reduction (BSER) for existing coal-fired EGUs. Second, EPA is proposing new regulations that provide direction to both EPA and the states on the implementation of emission guidelines. The new proposed implementing regulations would apply to this action and any future emission guideline issued under section 111(d) of the Clean Air Act (CAA). Third, the Agency is proposing revisions to the New Source Review (NSR) program that will help prevent NSR from being a barrier to the implementation of efficiency projects at EGUs. DATES: Comments. Comments must be received on or before October 30, 2018. Under the Paperwork Reduction Act (PRA), comments on the information collection provisions are best assured of consideration if the Office of Management and Budget (OMB) receives a copy of your comments on or before October 1, 2018. Public hearing: 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 document. ADDRESSES: Comments. Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2017-0355, 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 EPA treats submitted comments. Regulations.gov is our preferred method of receiving comments. 1 However, other submission methods are accepted: 1 Comments submitted on the proposed repeal will be considered in the promulgation of this rulemaking so there is no need to resubmit comments that have already been timely submitted. • Email: a-and-r-docket@epa.gov. Include Docket ID No. EPA-HQ-OAR-2017-0355 in the subject line of the message. • Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-2017-0355. • 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-2017-0355, 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. Nicholas Swanson, 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) 541-4080; fax number: (919) 541-4991; and email address: swanson.nicholas@epa.gov. SUPPLEMENTARY INFORMATION: Docket. EPA has established a docket for this rulemaking under Docket ID No. EPA-HQ-OAR-2017-0355. 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-2017-0355. 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. 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. 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 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 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, 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 EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, 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 EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets. Throughout this proposal, EPA is soliciting comment on numerous aspects of the proposed rule. EPA has indexed each comment solicitation with an alpha-numeric identifier ( e.g., “C-1”, “C-2”, “C-3”, . . .). EPA included similar identifiers in the advance notice of proposed rulemaking (ANPRM) and asked commenters to identify the main topic area that corresponded with their comment. In this proposal, we are modifying this approach to include a unique identifier for each individual comment solicitation to provide a consistent framework for effective and efficient provision of comments. Accordingly, we ask that commenters include the corresponding identifier when providing comments relevant to that comment solicitation. We ask 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. We emphasize that we are not limiting comment to these identified areas and encourage provision of any other comments relevant to this proposal. Submitting CBI. Do not submit information containing CBI to EPA through https://www.regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to 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-2017-0355. Preamble acronyms and abbreviations. We use 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, EPA defines the following terms and acronyms here: ACE Affordable Clean Energy Rule AEO Annual Energy Outlook ANPRM Advance Notice of Proposed Rulemaking BACT Best Available Control Technology BSER Best System of Emission Reduction Btu British Thermal Unit CAA Clean Air Act CBI Confidential Business Information CCS Carbon Capture and Storage (or Sequestration) CFR Code of Federal Regulation CO 2 Carbon Dioxide CPP Clean Power Plan EGU Electric Utility Generating Unit EIA Energy Information Administration EPA Environmental Protection Agency FIP Federal Implementation Plan FR Federal Register GHG Greenhouse Gas HRI Heat Rate Improvement IGCC Integrated Gasification Combined Cycle kW Kilowatt kWh Kilowatt-hour MW Megawatt MWh Megawatt-hour NAAQS National Ambient Air Quality Standards NGCC Natural Gas Combined Cycle NO X Nitrogen Oxides NSPS New Source Performance Standards NSR New Source Review OMB Office of Management and Budget PM 2.5 Fine Particulate Matter PRA Paperwork Reduction Act PSD Prevention of Significant Deterioration RIA Regulatory Impact Analysis RTC Response to Comments SIP State Implementation Plan SO 2 Sulfur Dioxide UMRA Unfunded Mandates Reform Act of 1995 U.S. United States VFD Variable Frequency Drive Organization of this document. The information in this preamble is organized as follows: I. General Information A. Executive Summary B. Where can I get a copy of this document and other related information? II. Background A. Regulatory and Judicial History of GHG Requirements for EGUs B. Executive Order 13783 and EPA's Review of the CPP C. Industry Trends III. Legal Authority A. Authority to Revisit Existing Regulations B. Authority to Regulate EGUs C. Legal Authority for Determination of the BSER IV. Affected Sources V. Determination of the BSER A. Identification of the BSER B. HRIs for Steam-Generating EGUs C. HRI for Natural Gas-fired Stationary Combustion Turbines D. Other Considered Systems of GHG Emission Reductions VI. State Plan Development A. Establishing Standards of Performance B. Flexibilities for States and Sources C. Submission of State Plans VII. Proposed New Implementing Regulations for Section 111(d) Emission Guidelines A. Changes to the Definition of “Emission Guideline” B. Updates to Timing Requirements C. Compliance Deadlines D. Completeness Criteria E. Standard of Performance F. Variance VIII. New Source Review Permitting of HRIs A. What is New Source Review? B. Interaction of NSR and the ACE Rule C. ANPRM Solicitation and Comments Received D. Proposing NSR Changes for Improved ACE Implementation IX. 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 forgone benefits of the proposed action? 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 EPA is proposing the Affordable Clean Energy (ACE) rule as a replacement to the CPP (promulgated on October 23, 2015, 80 FR 64662), which sets GHG emission guidelines for existing EGUs. This proposal relies in part on the legal analysis presented in the CPP repeal that was proposed on October 16, 2017, 82 FR 48035. In the proposed repeal, EPA asserted that the BSER in the CPP exceeded EPA's authority because it established the BSER using measures that applied to the power sector as whole, rather than measures that apply at and to, and can be carried out at the level of, individual facilities. This proposed action aligns with EPA's statutory authority and obligation because, as EPA has done in the dozens of NSPSs issued to date, the BSER is to be determined by evaluating technologies or systems of emission reduction that are applicable to, at, and on the premises of the facility for an affected source. This proposal will ensure that coal-fired power plants (the most carbon dioxide (CO 2 ) intensive portion of the electricity generating fleet) address their contribution to climate change by reducing their CO 2 intensity ( i.e., the amount of CO 2 they emit per unit of electricity generated). Accordingly, the proposed ACE rule consists of three discrete sections. First, EPA is proposing to determine the BSER for existing EGUs based on HRI measures that can be applied at an affected source. EPA also proposes a corresponding emission guideline clarifying the roles of EPA and the states under CAA section 111(d). EPA's primary role in implementing CAA section 111(d) is to provide emission guidelines that inform the development, submittal, and implementation of state plans, and to subsequently determine whether submitted state plans are approvable. Per the CAA, once EPA publishes a final emission guideline, states have the primary role of developing standards of performance consistent with application of the BSER. Congress also expressly required that EPA allow states to consider source-specific factors—including, among other factors, the remaining useful life of the affected source—in applying a standard of performance. In this way, the state and federal roles complement each other as EPA has the authority and responsibility to determine a nationally applicable BSER while the states have the authority and responsibility to establish and apply existing source standards of performance, in consideration of source-specific factors. Second, EPA is proposing new implementing regulations that apply to this action and any future emission guidelines promulgated under CAA section 111(d). The purpose of proposing new implementing regulations is to harmonize our 40 CFR part 60 subpart B regulations with the statute by making it clear that states have broad discretion in establishing and applying emissions standards consistent with the BSER. The discussion for the proposed revisions is found in Section VII below. Third, EPA is proposing to give the owners/operators of EGUs more latitude to make the efficiency improvements that are consistent with EPA's proposed BSER without triggering onerous and costly NSR permit requirements. This change will allow states, in establishing standards of performance, to consider HRIs that would otherwise not be cost-effective due to the burdens incurred from triggering NSR. The discussion of this issue is included in Section VII. As with other regulations of this nature, this notice concludes with a summary of the impacts of this proposal and is supported by a Regulatory Impact Analysis (RIA) that can be found in the docket for this action. As reported in the RIA, EPA evaluated three illustrative policy scenarios modeling HRI at coal-fired EGUs. EPA estimates that there are cost savings under two of the three illustrative scenarios, with average annual compliance costs ranging from a cost savings of about $0.5 billion to a cost of about $0.3 billion. As noted previously, this action is preceded by a proposed repeal of the CPP. 2 That proposal included a detailed legal analysis demonstrating that “building blocks” two and three of the CPP exceeded EPA's authority. That analysis is incorporated into this proposal. Because two of the three “building blocks” used to establish the CPP emission guidelines were legally flawed (and because “building block” one was not designed in such a manner that it could or was intended to stand on its own without the other building blocks), EPA proposed that the CPP emission guidelines be withdrawn. With the ACE rule, EPA proposes to possibly replace the CPP with a rule that corrects the fundamental legal flaws in the CPP to more appropriately balance federal and state responsibilities under CAA section 111(d), and revise the NSR program as it applies to affected EGUs to better accommodate energy efficiency projects. 2 The accompanying RIA focuses on presenting the difference between the CPP and the concepts in ACE, but also includes a scenario with no CPP, providing sufficient information to understand the impact of a full repeal of the CPP, a two-step approach in which the CPP is repealed and then an alternative BSER is put in place or a case in which the Agency revises the BSER promulgated in the CPP. This proposed action has been informed by comments submitted in response to the ANPRM, published December 28, 2017, see 82 FR 61507. EPA notes that it does not intend to respond to the comments received on the ANPRM. If commenters believe that any of their previously submitted comments are still applicable, they should resubmit those comments to this rulemaking to ensure they are considered. B. 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 EPA Administrator, EPA will post a copy of this proposed action at https://www.epa.gov/stationary-sources-air-pollution/electric-utility-generating-units-emission-guidelines-greenhouse. Following publication in the Federal Register , EPA will post the Federal Register version of the proposal and key technical documents at this same website. II. Background A. Regulatory and Judicial History of GHG Requirements for EGUs When passing and amending the CAA, Congress sought to address and remedy the dangers posed by air pollution to human beings and the environment. While the text of the CAA does not reflect an explicit intent on the part of Congress to address the potential effects of elevated atmospheric GHG concentrations, the Supreme Court in Massachusetts v. EPA, 549 U.S. 497 (2007), concluded that Congress had drafted the CAA broadly enough so that GHGs constituted air pollutants within the meaning of the CAA. EPA subsequently determined that emissions of GHGs from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. See 74 FR 66496 (December 15, 2009). This determination required EPA to regulate GHG emissions from motor vehicles. In 2009, and again in 2016, the EPA Administrator issued findings under sections 202(a) and 231(a)(2)(A) of the Clean Air Act, respectively, that the current, elevated concentrations of six well-mixed GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare of current and future generations in the United States. 3 In 2015, after determining that GHGs from EGUs merited regulation under CAA section 111, EPA promulgated standards of performance for new, modified, and reconstructed EGUs under section 111(b). 80 FR 64510. Consequentially, this led to EPA's obligation to develop a 111(d) rule for existing EGUs, as described in Section III. EPA believes that the BSER in ACE is consistent both with our legal authorities under 111(d) and with what is technically feasible and appropriate for coal-fired power plants. Therefore, EPA believes that the emission reductions required from state plans are the appropriate amount for a 111(d) rule. 3 “Finding that Greenhouse Gas Emissions From Aircraft Cause or Contribute to Air Pollution That May Reasonably Be Anticipated to Endanger Public Health and Welfare,” 81 FR 54422 (August 15, 2016). While the market in the power sector is driving GHG emissions down, the EPA, by proposing this emission guideline, is reinforcing the market in many respects and also ensuring that available emission reductions that are not market driven are achieved. Many regulations are promulgated to correct market failures, which otherwise lead to a suboptimal allocation of resources within the free market. Air quality and pollution control regulations address “negative externalities” whereby the market does not internalize the full opportunity cost of production borne by society as public goods such as air quality are unpriced. While recognizing that optimal social level of pollution may not be zero, GHG emissions impose costs on society, such as negative health and welfare impacts, that are not reflected in the market price of the goods produced through the polluting process. For this regulatory action the good produced is electricity. If a fossil fuel-fired electricity producer pollutes the atmosphere when it generates electricity, this cost will be borne not by the polluting firm but by society as a whole, thus the producer is imposing a negative externality, or a social cost of emissions. The equilibrium market price of electricity may fail to incorporate the full opportunity cost to society of generating electricity. Consequently, absent a regulation on emissions, the EGUs will not internalize the social cost of emissions and social costs will be higher as a result. This regulation will work towards addressing this market failure by causing affected EGUs to begin to internalize the negative externality associated with CO 2 emissions. Further discussion of GHG impacts, as well as the benefits of this proposal, can be found in the RIA for this action. As detailed in Chapter 3 of the RIA, EPA evaluated three illustrative policy scenarios representing ACE. These scenarios are projected to result in a decrease of annual CO 2 emissions of about 7 million to 30 million short tons relative to a future without a CAA section 111(d) regulation affecting the power sector. Along with the 111(b) standard, EPA issued, under CAA section 111(d), its “Clean Power Plan,” consisting of GHG emission guidelines for existing EGUs, which states would use to develop emission standards as mentioned above. 80 FR 64662 (October 23, 2015). In February 2016, the U.S. Supreme Court stayed implementation of the CPP pending judicial review. West Virginia v. EPA, No. 15A773 (S.Ct. Feb. 9, 2016). In March 2017, President Trump issued Executive Order 13873, which among other things, directed EPA to reconsider the CPP. After considering the statutory text, context, legislative history and purpose, and in consideration of EPA's historical practice under CAA section 111 as reflected in its other existing CAA section 111 regulations and of certain policy concerns, EPA proposed to repeal the CPP. See 82 FR 48035. In a separate but related action, EPA published an ANPRM to solicit comment on what EPA should include in a potential new existing source regulation under CAA section 111(d), including soliciting comment on aspects of the respective roles of the states and EPA in that process, on the BSER in context of the statutory interpretation contained in the proposed repeal of the CPP, on what systems of emission reduction might be available and appropriate, and the potential flexibility that could be afforded under the NSR program to improve the implementation of a potential new existing source regulation for EGUs under CAA section 111(d). 82 FR 61507 (December 28, 2017). EPA received more than 270,000 comments on the ANPRM, which have informed this proposed rulemaking. In ACE, EPA is proposing to determine that the BSER for GHG emissions from existing coal-fired EGUs is heat rate improvements that can be applied at the source, consistent with the legal interpretation expressed in the proposed repeal. The Agency is also, in this action, clarifying the respective roles of the states and EPA under CAA section 111(d), including by proposing revisions to the regulations, in 40 CFR part 60 subpart B, implementing that section. Section 111(d)(1) of the CAA states that EPA's “Administrator shall prescribe regulations which shall establish a procedure . . . under which each State shall submit to the Administrator a plan which (A) establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under this section would apply if such existing source were a new source, and (B) provides for the implementation and enforcement of such standards of performance.” See 42 U.S.C. 7411(d). CAA section 111(d)(1) also requires the Administrator to “permit the State in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.” Id. As the plain language of the statute provides, EPA's authorized role under CAA section 111(d)(1) is to develop a procedure for states to establish standards of performance for existing sources. Indeed, the Supreme Court has acknowledged the role and authority of states under section 111(d): This provision allows “each State to take the first cut at determining how best to achieve EPA emissions standards within its domain.” Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2539 (2011). The Court addressed the statutory framework as implemented through regulation, under which EPA promulgates emission guidelines and the states establish performance standards: “For existing sources, EPA issues emissions guidelines; in compliance with those guidelines and subject to federal oversight, the States then issue performance standards for stationary sources within their jurisdiction, [42 U.S.C.] § 7411(d)(1).” Id. at 2537-38. As contemplated by CAA section 111(d)(1), states possess the authority and discretion to establish appropriate standards of performance for existing sources. CAA section 111(a)(1) defines “standard of performance” as “a standard of emissions of air pollutants which reflects” what is colloquially referred to as the “Best System of Emission Reduction” or “BSER”— i.e., “the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” 42 U.S.C. 7411(a)(1) (emphasis added). In order to effectuate the Agency's role under CAA section 111(d)(1), EPA promulgated implementing regulations in 1975 to provide a framework for subsequent EPA rules and state plans under section 111(d). See 40 CFR part 60, subpart B (hereafter referred to as the “implementing regulations”). The implementing regulations reflect EPA's principal task under CAA section 111(d)(1), which is to develop a procedure for states to establish standards of performance for existing sources through state plans. EPA is proposing to promulgate an updated version of the implementing regulations as part of ACE (see Section VII). Per the new proposed implementing regulations, EPA effectuates its role by publishing, an “emission guideline” 4 that, among other things, contains EPA's determination of the BSER for the category of existing sources being regulated. See 40 CFR 60.22a(b) [“Guideline documents published under this section will provide information for the development of State plans, such as: . . . (4) An emission guideline that reflects the application of the best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated.”] In undertaking this task, EPA “will specify different emissions guidelines . . . for different sizes, types and classes of . . . facilities when costs of control, physical limitations, geographic location, or similar factors make subcategorization appropriate.” 40 CFR 60.22(b)(5). 4 See Section VII.A. for proposed changes to the definition of “emission guideline” as part of EPA's proposed new implementing regulations. In short, under EPA's new proposed regulations implementing CAA section 111(d), which tracks with the existing implementing regulations in this regard, the guideline document serves to “provide information for the development of state plans.” 40 CFR 60.22a(b), with the “emission guideline,” reflecting BSER as determined by EPA, being the principal piece of information states rely on to develop their plans that establish standards of performance for existing sources. Because the CAA cannot necessarily be applied to GHGs in the same manner as other pollutants, Utility Air Regulatory Group, 134 S. Ct. 2427, 2455 (2014) (Alito, J., concurring in part and dissenting in part), it is fortuitous that CAA section 111(d) recognizes that states possess considerable flexibility in developing their plans in response to the emissions guideline(s) established by EPA. Specifically, the Act requires that EPA permit states to consider, “among other factors, the remaining useful life” of an existing source in applying a standard of performance to such sources. CAA section 111(d)(1). Additionally, while CAA section 111(d)(1) clearly authorizes states to develop state plans that establish performance standards and provides states with certain discretion in determining appropriate standards, CAA section 111(d)(2) provides EPA specifically a role with respect to such state plans. This provision authorizes EPA to prescribe a plan for a state “in cases where the State fails to submit a satisfactory plan.” CAA section 111(d)(2)(A). EPA therefore is charged with determining whether state plans developed and submitted under section 111(d)(1) are “satisfactory,” and the proposed new implementing regulations at 40 CFR 60.27a accordingly provides timing and procedural requirements for EPA to make such a determination. Just as guideline documents may provide information for states in developing plans that establish standards of performance, they may also provide information for EPA to consider when reviewing and taking action on a submitted state plan, as the new proposed implementing regulations at 40 CFR 60.27a(c) references the ability of EPA to find a state plan as “unsatisfactory because the requirements of (the implementing regulations) have not been met.” 5 5 See also 40 FR 53343 (“If there is to be substantive review, there must be criteria for the review, and EPA believes it is desirable (if not legally required) that the criteria be made known in advance to the States, to industry, and to the general public. The emission guidelines, each of which will be subjected to public comment before final adoption, will serve this function.”). B. Executive Order 13783 and EPA's Review of the CPP On March 28, 2017, President Trump issued Executive Order 13783, which affirms the “national interest to promote clean and safe development of our Nation's vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” See Executive Order 13783, Section 1(a). The Executive Order directs all executive departments and agencies, including 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.” Id. Section 1(c). The Executive Order further affirms that it is “the policy of the United States that necessary and appropriate environmental regulations comply with the law.” Id. Section 1(e). Moreover, the Executive Order specifically directs EPA to review and initiate reconsideration proceedings to “suspend, revise, or rescind” the CPP, “as appropriate and consistent with law.” Id. Section 4(a)-(c). In a document signed the same day as Executive Order 13783, and published in the Federal Register at 82 FR 16329 (April 4, 2017), EPA announced that, consistent with the Executive Order, it was initiating its review of the CPP and providing notice of forthcoming proposed rulemakings consistent with the Executive Order. 6 In the course of EPA's review of the CPP, the Agency also reevaluated its interpretation of CAA section 111, and, on that basis, the Agency proposed to repeal the CPP. See 82 FR 48035. 6 EPA also withdrew the proposed federal plan and model trading rules, proposed amendments to certain regulations under 40 CFR part 60, subpart B, implementing CAA section 111(d), and proposed rule regarding the Clean Energy Incentive Plan. 82 FR 16144 (April 3, 2017). This action proposes a BSER for GHGs from existing EGUs in line with the interpretation presented in the proposed CPP repeal. See 82 FR 48038-42. Comments submitted on the proposed repeal will be considered in the promulgation of this rulemaking so there is no need to resubmit comments that have already been timely submitted. C. Industry Trends Carbon dioxide emissions in the power sector have steadily declined in recent years due to a variety of power industry trends, which are expected to continue. The reduction in power sector CO 2 emissions is the result of industry trends away from coal-fired generation and toward low- and zero-emitting generation sources. These trends have been driven by market factors, reduced electricity demand, and policy and regulatory efforts. These trends have resulted in a notable change to the country's overall generation mix, as more natural gas and renewable energy is used to generate electricity relative to coal-fired electricity. The price of natural gas is expected to remain low for the foreseeable future as improvements in drilling technologies and techniques continue to reduce the cost of extraction. In addition, the existing fleet of coal-fired EGUs is aging and there are very few new coal-fired generation projects under development. With a continued (but reduced) tax credit and declining capital costs, solar capacity will continue to grow through 2050 while tax credits that phase out for plants entering service through 2024 provide incentives for new wind capacity in the near-term. Some power plant generators have announced that they expect to continue to change their generation mix away from coal-fired generation toward natural-gas fired generation, renewables and more deployment of energy efficiency measures. All of these trends, in total, are expected to result in declining power sector CO 2 emissions. In the near-term, according to the U.S. Energy Information Administration's (EIA) 2018 Annual Energy Outlook, “the cumulative effect of increased coal plant retirements, lower natural gas prices and lower electricity demand in the AEO2018 Reference case is a reduction in the projected [CO 2 ] emissions from electric generators, even without the [CPP]. In 2020, electric power sector CO 2 emissions are projected to be 1.72 billion metric tons, which is 120 million metric tons (7 percent) lower than the projected level of CO 2 emissions in the AEO2017 Reference case without the CPP.” 7 In other words, these declining emission trends have continued to develop even in the absence of implementation of the CPP. 7 U.S. 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. In consideration of these ongoing and projected power sector trends and a resulting decline in power sector CO 2 emissions, EPA is soliciting comment on whether and how to consider such trends in developing CO 2 emission guidelines for the power sector. A comparison of EIA projections to EPA analysis for the original proposed CPP demonstrates that the rapid changes in the power sector are leading to CO 2 emission reductions at a faster rate than projected even a few years ago when the CPP was promulgated (Comment C-1). EPA also notes that CO 2 emissions are projected to increase over time in some EIA AEO side cases, and, given the uncertainties associated with long-term emission projections, solicits comments on the applicability of those alternative results. Because of the rapid pace of these power sector changes, it is difficult for sector analysts to fully account for these changing trends in near-term and long-term sector-wide projections. This means that regulatory decisions made today could be based on information that may very well be outdated within the next several years. If that is the case, work put in by federal and state regulatory agencies—as well as by the affected sources themselves—to address section 111(d) requirements could quickly be overtaken by external market forces which could make those efforts redundant or, even worse, put them in conflict with industry trends that are already reducing CO 2 emissions. III. Legal Authority A. Authority To Revisit Existing Regulations EPA's ability to revisit existing regulations is well-grounded in the law. Specifically, 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. The CAA complements EPA's inherent authority to reconsider prior rulemakings by providing the Agency with broad authority to prescribe regulations as necessary. 42 U.S.C. 7601(a); see also Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills, 81 FR 59276, 59277-78 (August 29, 2016). The authority to reconsider prior decisions exists in part because 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 when, as is the case here, 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). B. Authority To Regulate EGUs In the CPP, EPA stated that EPA's then-concurrent promulgation of standards of performance regulating CO 2 emissions from new, modified, and reconstructed EGUs triggered the need to regulate existing sources under CAA section 111(d). 80 FR 64715. In ACE, we are not re-opening any issues related to this conclusion, but for the convenience of stakeholders and the public, we will summarize our explanation here. We explained in the CPP that CAA section 111(d)(1) requires EPA to promulgate regulations under which states must submit state plans regulating “any existing source” of certain pollutants “to which a standard of performance would apply if such existing source were a new source.” Id. Under CAA section 111(a)(2) and 40 CFR 60.15(a), a “new source” is defined as any stationary source, the construction, modification, or reconstruction of which is commenced after the publication of proposed regulations prescribing a standard of performance under CAA section 111(b) applicable to such source. We noted that, at that time, we were concurrently finalizing a rulemaking under CAA section 111(b) for CO 2 emissions from affected EGUs, which provided the requisite predicate for applicability of CAA section 111(d). Id. EPA explained in the 111(b) rule (80 FR 64529) that “CAA section 111(b)(1)(A) requires the Administrator to establish a list of source categories to be regulated under section 111. A category of sources is to be included on the list `if in [the Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health and welfare.' ” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly” component and the “endanger public health and welfare” component of the determination. Then, for the source categories listed under section 111(b)(1)(A), the Administrator promulgates, under section 111(b)(1)(B), “standards of performance for new sources within such category.” EPA further explained that, because EGUs had previously been listed, it was unnecessary to make an additional finding. The Agency also noted that, under section 111(b)(1)(A), findings are category specific and not pollutant specific, so a new finding is not needed with regard to a new pollutant. The Agency further asserted that, even if it were required to make a finding, given the large amount of CO 2 emitted from this source category (the largest single stationary source category of emissions of CO 2 by far) that EGUs would easily meet that standard. The Agency further noted that, given the large amount of emissions from the source category, it was not necessary in that rule “for the EPA to decide whether it must identify a specific threshold for the amount of emissions from a source category that constitutes a significant contribution.” 80 FR 64531. That CAA section 111(b) rulemaking remains on the books, although EPA is currently considering revising it. Accordingly, it continues to provide the requisite predicate for applicability of CAA section 111(d). Any comments on the issues discussed in this subsection would be more appropriately addressed to the docket on EPA's intended forthcoming proposal with regard to the new source rule. C. Legal Authority for Determination of the BSER As discussed above, EPA's authorized role under CAA section 111(d) is to establish a procedure under which states submit plans establishing standards of performance for existing sources, reflecting the application of the best system of emission reduction that EPA has determined is adequately demonstrated for the source category. In the CPP, EPA determined that the BSER for CO 2 emissions from existing fossil fuel-fired power plants was the combination of emission rate improvements and limitations on overall emissions by affected power plants that can be accomplished through a combination of three sets of measures, which the EPA called “building blocks”: 1. Improving heat rate at affected coal-fired steam generating units; 2. Substituting increased generation from lower-emitting existing natural gas combined cycle units for decreased generation from higher-emitting affected steam generating units; and 3. Substituting increased generation from new zero-emitting renewable energy generating capacity for decreased generation from affected fossil fuel-fired generating units. While building block 1 constituted measures that could be applied directly to a source—that is, integrated into its design or operation—building blocks 2 and 3 employed generation-shifting measures that departed from this traditional, source-specific approach to regulation. As explained in the proposed repeal, after reconsidering the statutory text, context and legislative history, and in consideration of EPA's historical practice under CAA section 111 as reflected in its other existing section 111 regulations, the Agency proposes to return to a reading of section 111(a)(1) (and its constituent term, “best system of emission reduction”) as being limited to emission reduction measures that can be applied to or at an individual stationary source. That is, such measures must be based on a physical or operational change to a building, structure, facility or installation at that source rather than measures the source's owner or operator can implement at another location. For a more detailed discussion of EPA's proposed interpretation, see 82 FR 48039-42. In proposing ACE, EPA offers additional legal rationale to support its determination that heat-rate improvements constitute the BSER. EPA solicits comment on these additional legal interpretations (Comment C-2). First, as explained in the CPP preamble, reduced utilization “does not fit within our historical and current interpretation of the BSER.” See 80 FR 64780; see also id. at 64762 (“EPA has generally taken the approach of basing regulatory requirements on controls and measures designed to reduce air pollutants from the production process without limiting the aggregate amount of production.”) Whereas some emission reduction measures (such as a scrubber) may have an incidental impact on a source's production levels, reduced utilization is directly correlated with a source's output. Moreover, predicating a CAA section 111 standard on a source's non-performance would inappropriately inject the Agency into an owner/operator's production decisions. In returning to our historical understanding of and practice under section 111, we reiterate that reduced utilization is not a valid system of emission reduction for purposes of establishing a standard of performance. EPA believes our proposed interpretation that the BSER be limited to measures that can be applied at or to a source does not command a different result. Second, as explained in the proposed repeal notice, interpretative constraints that may apply to interpreting CAA section 111(a)(1) ( i.e., determining what types of measures that may be considered as the BSER) for purposes of setting a new source performance standard under section 111(b) reasonably may be applied to interpreting the BSER for purposes of setting existing source standards under section 111(d) as well (and, given that “standard of performance” is given a unitary definition for purposes of the entire statutory section, applying the same interpretative constraints may in fact be required). For example, we proposed that “the BSER should be interpreted as a source-specific measure, in light of the fact that [Best Available Control Technology, or BACT] standards, for which the BSER is expressly linked by statutory text, are unambiguously intended to be source-specific.” 8 See 82 FR 48042. 8 See 40 CFR 52.21(b)(12); see also 42 U.S.C. 7479(3). Under the CAA and applicable regulations, certain preconstruction permits must contain emissions limitations based on application of BACT for certain regulated pollutants. EPA recommends that permitting authorities follow a five-step “top-down” BACT analysis, which calls for all available control technologies for a given pollutant to be identified and ranked in descending order of control effectiveness. 9 The options are then assessed in consideration of technical, energy, environmental and economic factors until an option is selected as BACT. 9 The five steps are: (1) Identify all available control technologies; (2) eliminate technically infeasible options; (3) rank remaining control technologies; (4) evaluate most effective controls and document results; and (5) select the BACT. In reviewing our BACT guidance, we have identified additional interpretive constraints that may be applied to CAA section 111. Specifically, in EPA's PSD and Title V Permitting Guidance for Greenhouse Gases, we explained that a BACT analysis “need not necessarily include inherently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant.” Id. at 26 (emphasis added). Furthermore, we explained that “BACT should generally not be applied to regulate the applicant's purpose or objective for the proposed facility.” Id. Indeed, “EPA has recognized that the initial list of control options for a BACT analysis does not need to include `clean fuel' options that would fundamentally redefine the source. Such options include those that would require a permit applicant to switch to a primary fuel type ( i.e., coal, natural gas or biomass) other than the type of fuel that an applicant proposes to use for its primary combustion process.” Id. at 27. EPA has even noted that “applicants proposing to construct a coal-fired electric generator, have not been required by EPA as part of a BACT analysis to consider building a natural gas-fired electric turbine although the turbine may be inherently less polluting per unit product (in this case electricity).” 10 Although in the CPP we believed that EPA's “redefining the source” policy was not relevant for purposes of section 111(d), see CPP RTC Chapter 1A, 170-72, we now believe that such a policy is relevant in light of the relationship between BACT and BSER. In the response to comments accompanying the CPP, EPA rejected the relevance to BSER under section 111 of the Agency's general policy against “redefining the source” in the context of PSD/BACT. EPA now believes that it was incorrect in its response, and that it is worth examining this point in some detail because it encapsulates several key aspects of the CPP's interpretation of section 111 in general and section 111(d) in particular that EPA now proposes to conclude in ACE are not appropriate interpretations of the statute. 10 New Source Review Workshop Manual, at B.13 (Draft) (October 1990), available at https://www.epa.gov/sites/production/files/2015-07/documents/1990wman.pdf. In its response to comments, EPA largely based its rejection of the relevance of PSD to BSER on what it saw as the salient distinctions between the sources subject to, and mode of operation of, the two statutory programs. In this regard, EPA spoke of the “distinct context of the PSD program, which involves the case-by-case review of the construction of an individual stationary source. . . . BACT is not applicable to unmodified existing sources nor is it applied on a source category basis. The CAA's PSD program is administered primarily by state and local permitting authorities as [an] individualized preconstruction requirement under CAA section 165. Under section 111(d), the Administrator identifies a list of adequately demonstrated control options in use by the industry, selects the best of those control options after considering cost and other factors, then selects an achievable limit for the category through the application of the BSER across the industry. . . .” (Emphases added.) Here, EPA's response disregarded the fact that under CAA section 111(d), the statute explicitly tasks states—not the Administrator—with “establishing standards of performance” for existing sources, and that the statute expressly requires EPA to allow the state to take into account source-specific factors when doing so. A “standard of performance” is defined at 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” BSER. (Emphasis added.) Therefore, it is the state, not EPA, that is tasked in the first instance with “select[ing] an achievable limit” for existing sources—and section 111(d)'s emphasis on source-specific factors at the very least renders questionable EPA's unqualified assertion that BSER for existing sources “is applied on a source category basis.” In the instant proposal, EPA proposes to give full meaning to these textual and structural features of the existing-source program under section 111(d) that render it in important respects distinct from the new-source program under section 111(b) and similar to the source-by-source PSD program: Section 111(d), unlike section 111(b), is implemented in the first instance by the states, and it is expressly linked to source-specific factors. These similarities counsel against EPA's prior rejection of the relevance of the general policy under PSD against “redefining the source.” Furthermore, speaking of the generation-shifting measures that constituted the second and third “building blocks” of the CPP, EPA asserted that “those measures are part of the business purposes and objectives within the power sector. Accordingly, the BSER, which incorporates building blocks 2 and 3, cannot be said to force a fundamental redefinition of the business of generating electric power.” (Emphases added.) The emphasized phrases reveal the influence of EPA's statutory interpretation underlying the CPP: That EPA can regulate under CAA section 111 at the level of an entire industrial sector, and that the business that it is regulating is “generating electric power” writ large—rather than a recognition in line with the statute's text and structure, and EPA's practice prior to the CPP, of regulating the performance of individual sources through measures carried out at and by the individual source. EPA rested on its discretionary prerogative: “EPA's policies under CAA section 165 regarding the construction of individual sources are not controlling for purposes of establishing category-wide standards for existing sources under CAA section 111(d). Even if the PSD `redefining the source' policies were applicable in this context, it would be within the Administrator's discretion to consider requiring a fundamental redesign of a newly constructed or modified source[ ]. EPA's case-by-case application of CAA section 165 in the PSD program does not limit the Administrator's discretion in establishing an emission guideline for an entire category of existing sources under CAA section 111(d).” (Emphases added.) EPA has explained, both in the proposed repeal and the instant proposal, why it is proposing to conclude that the statute does not, in fact, delegate discretion to the Administrator to “establish . . . for an entire category of existing sources” standards that can only be accomplished by “a fundamental redesign” of that category, of the generation mix, and of the division of jurisdiction over electricity generation within the federal government and between the federal government and the states. But to the extent that the Agency, due to the fact that Congress did not expressly forbid such an approach, does possess that discretion, today it proposes not to exercise it. Third, notwithstanding the relationship between BACT and BSER, we believe that measures “redefining the source” should be excluded from consideration for purposes of CAA section 111(d). See, e.g., Sierra Club v. EPA, 499 F.3d 653, 655 (7th Cir. 2007) (“Refining the statutory definition . . . to exclude redesign is the kind of judgment by an administrative agency to which a reviewing court should defer.”). Indeed, the policy against redefining a source is even more sensible when applied to existing sources. Under section 111(d), regulated sources are well past the proposal stage and redefining such sources would likely require, at a minimum, significant modification and could even require decommissioning, redesign and new construction. Accordingly, we propose to recognize that the BSER analysis need not include options that would “fundamentally redefine the source,” irrespective of the application of that policy under PSD. For purposes of ACE, therefore, we did not consider natural gas repowering ( i.e., converting from a coal-fired boiler to a gas-fired turbine) or refueling ( i.e., converting from a coal-fired boiler to a natural gas-fired boiler) as a system of emission reduction for coal-fired steam generating units. Fourth, the legislative history underlying CAA section 111 confirms that Congress intended this provision to be source oriented. The Senate Committee Report on Senate Bill 4358 explained that “[t]he provisions for new source performance standards [ i.e., S. 4538, section 113] 11 are designed to insure [sic] that new stationary sources are designed, built, equipped, operated, and maintained so as to reduce emissions to a minimum.” S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 415-16 (emphasis added). Similarly, “[e]mission standards developed under [S. 4538, section 114] would be applied to existing stationary sources. However, the Committee recognizes that certain old facilities may use equipment and processes which are not suited to the application of control technology.” Id. at 1970 CAA Legis. Hist. at 419 (emphasis added) (noting further that in such cases, the application of standards could be waived). 11 Section 113 of Senate Bill 4538 would become CAA section 111; section 114 of the Senate Bill would become CAA section 111(d). The proposed interpretive scope of the BSER is reasonable because it focuses the BSER on the performance of the emitting unit itself, rather than the performance of the emitting unit and the transmission system to which it belongs. EPA's area of expertise is control of emissions at the source. EPA is not the expert agency with regard to electricity management. FERC is the expert at the federal level and public utility commissions are the experts at the state and local level. Numerous factors might be considered in determining which power plants dispatch on a given system or operate at any given time ( e.g., cost of service, voltage support, electricity demand, availability of renewable resources, etc. ). Moreover, numerous factors are relevant in determining how much new/replacement generation capacity is needed and what types of generating resources best satisfy that need. EPA has no express legal authority and no particular expertise in any of these areas. This is particularly relevant because, as noted below, there are already significant changes taking place within the power sector that are resulting in shifts away from coal-fired generation to new technologies such as renewables. This shift is creating tremendous strain on the power infrastructure even without the added pressures of an EPA mandate to further shift away from additional coal-fired generation. Many experts have expressed concern that these pressures could create reliability problems. As DOE noted in a 2017 report on electricity markets and reliability, “Ultimately, the continued closure of traditional baseload power plants calls for a comprehensive strategy for long-term reliability and resilience. States and regions are accepting increased risks that could affect the future reliability and resilience of electricity delivery for consumers in their regions. Hydropower, nuclear, coal, and natural gas power plants provide essential reliability services and fuel assurance critical to system resilience. A continual comprehensive regional and national review is needed to determine how a portfolio of domestic energy resources can be developed to ensure grid reliability and resilience.” 12 Because EPA believes it is not appropriate to further challenge the nation's electricity system while these important technical and policy issues are being addressed. EPA believes that it is reasonable to focus on a “BSER” limited to consideration of emission control measures that can be applied at or to coal-fired units, ensuring that regardless of how much coal-fired generation remains, that generation is operated to minimize CO 2 emissions. 12 U.S. DOE, Staff Report to the Secretary on Electricity Markets and Reliability (August 2017) at 14, available at https://www.energy.gov/sites/prod/files/2017/08/f36/Staff%20Report%20on%20Electricity%20Markets%20and%20Reliability_0.pdf. Also, the proposed interpretive scope of the BSER is reasonable considering the several important economic, policy and technology shifts occurring in the power sector. The first change is being driven by low natural gas prices that make lower carbon-emitting NGCC units more competitive as compared to higher carbon-emitting coal plants. Another important change is driven by both technology changes and by state and national energy policy decisions that have made renewable energy ( e.g., solar and wind energy) more competitive compared to coal and natural gas. The third notable change is driven by aging coal plants, which considering the economic competitive pressures driven by natural gas and renewable generation, are leading companies to conclude that a significant number of coal plants are reaching the end of their useful economic life or are no longer economic to operate. These trends have driven down GHG emissions from power plants, which were also key components to the BSER as defined in the CPP. In fact, the analysis that EPA has done for ACE (see RIA), as well as analysis by many others (including EIA), show that these trends have already well outpaced the projections that went into the CPP for many states. For this reason, establishing a BSER on assumptions for generation by various sources that accounts for the continuation of these trends into the future would create significant work for both states and sources that may or may not result in emission reductions from ACE if the actual trends once again prove to be stronger than projected. While some might suggest that this argues that the BSER in ACE should still follow the same approach as the CPP, adjusting this proposal to be even more stringent ignores the fact that the uncertainties that have resulted in faster than projected emission reductions are also uncertain in the opposite direction. From 2005 to 2008, gas prices experienced several unexpected peaks that were not anticipated. If this were to happen in the future, it would make any rule based on CPP-type assumptions significantly more expensive. Similarly, while the recent past has shown continued advances in renewable cost and performance, it is not certain that those trends will be sustained. It should be noted that federal tax subsidies that have been key to this trend are set to expire over the next several years which may play a role in the future. Because of these significant uncertainties that can have large impacts on electric reliability and the cost of electricity to consumers, EPA believes that this further supports the unreasonableness of basing the BSER on generation-shifting measures. Regardless of the path that the power sector takes, coal-fired power plants are likely to be an important part of the generation mix for the foreseeable future, therefore EPA believes it is reasonable to ensure that the remaining coal-fired generation (which is also the most CO 2 intensive portion of the power sector) focuses on reducing that CO 2 emission intensity to the extent technically feasible considering cost. EPA believes that a BSER focused on making these plants as efficient as possible is the best way to ensure GHG emission reductions regardless of other factors such as technology changes for other types of generation, changes in fuel price, changes in electricity demand or changes in energy policy that neither environmental regulators nor power companies have the power to control. IV. Affected Sources EPA is proposing that an affected EGU subject to regulation upon finalization of ACE is any fossil fuel-fired electric utility steam generating unit ( i.e., utility boilers) that is not an integrated gasification combined cycle (IGCC) unit ( i.e., utility boilers, but not IGCC units) that was in operation or had commenced construction as of August 31, 2018, 13 and that meets the following criteria. 14 To be an affected EGU, a fossil fuel-fired electric utility steam generating unit must serve a generator capable of selling greater than 25 MW to a utility power distribution system and have a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel). 13 Under section 111(a) of the CAA, determination of affected sources is based on the date that EPA proposes action on such sources. January 8, 2014 is the date the proposed GHG standards of performance for new fossil fuel-fired EGUs were published in the Federal Register (79 FR 1430). 14 To be clear, this definition of an affected EGU does not, at this time, include stationary combustion turbines for reasons discussed later in this document. EPA is proposing different applicability criteria than in the CPP to reflect EPA's determination of the BSER for only fossil fuel-fired electric utility steam generating units. In ACE, EPA does not identify a BSER for stationary combustion turbines and IGCC units and, thus, such units are not affected EGUs for purposes of this action (see discussion below in Section V.B). It should be noted, in the CPP's identification of the BSER, no HRIs were identified as the BSER for stationary combustion turbines and IGCC units. Nevertheless, EPA solicits comment on systems of emission reduction that might be the BSER for these types of EGUs (Comment C-3). EPA notes that, under the CPP, certain EGUs were not considered to be affected EGUs, and therefore were exempt from inclusion in a state plan. Similarly, EPA is proposing for ACE, the following EGUs would be excluded from a state's plan: (1) Those units subject to 40 CFR 60 subpart TTTT as a result of commencing modification or reconstruction; (2) steam generating units subject to a federally enforceable permit limiting net-electric sales to one-third or less of their potential electric output or 219,000 MWh or less on an annual basis; (3) non-fossil units ( i.e., units capable of combusting at least 50 percent non-fossil fuel) that have historically limited the use of fossil fuels to 10 percent or less of the annual capacity factor or are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (4) units that serve a generator along with other steam generating unit(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit) is 25 MW or less; (5) municipal waste combustor unit subject to 40 CFR part 60, subpart Eb; or (6) commercial or industrial solid waste incineration units that are subject to 40 CFR part 60, subpart CCCC. EPA solicits comment on whether there should be a different definition of affected EGUs for ACE (Comment C-4). V. Determination of the BSER CAA section 111(d)(1) directs EPA to promulgate regulations establishing a CAA section 110-like procedure under which states submit state plans that establish “standards of performance” for emissions of certain air pollutants from sources which, if they were new sources, would be subject to new source standards under section 111(b), and that provide for the implementation and enforcement of those standards of performance. The term “standard of performance” is defined in 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 [BSER] which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” Thus, EPA is authorized to determine the BSER for affected sources. See also 40 CFR 60.22. In making this determination, EPA identifies all “adequately demonstrated” 15 “system[s] of emission reduction” for a particular source category and then evaluates those systems to determine which is the “best” 16 while “taking into account” the factors of “cost . . . nonair quality health and environmental impact and energy requirements.” Because CAA section 111 does not set forth the weight that should be assigned to each of these factors, courts have granted the Agency a great degree of discretion in balancing them. Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (internal citations omitted). 15 Case law under CAA section 111(b) explains that “[a]n adequately demonstrated system is one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. Cir. 1973). While some of these cases suggest that “[t]he Administrator may make a projection based on existing technology,” Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973), the D.C. Circuit has also noted that “there is inherent tension” between considering a particular control technique as both “an emerging technology and an adequately demonstrated technology,” Sierra Club v. Costle, 657 F.2d 298, 341 n.157 (D.C. Cir. 1981). See also NRDC v. Thomas, 805 F.2d 410, n. 30 (D.C. Cir. 1986) (suggesting that “a standard cannot both require adequately demonstrated technology and also be technology-forcing.”). Nevertheless, EPA appears to “have authority to hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are feasible.” Sierra Club, 657 F.2d at 364. 16 The D.C. Circuit recognizes that EPA's evaluation of the “best” system must also include “the amount of air pollution as a relevant factor to be weighed . . . .” Id. at 326. CAA section 111(d)(1) assigns responsibility to the states for establishing standards of performance for affected existing sources—in contrast to section 111(b), which directs EPA to set standards of performance for affected new sources. A. Identification of the BSER In ACE, EPA identified several systems of emission reduction for existing fossil-fuel fired steam generating EGUs ( i.e., heat rate improvements; carbon capture and storage; and fuel co-firing, including with natural gas and biomass) and evaluated each of these systems to determine which is the “best” while taking into account cost, nonair quality health and environmental impact and energy requirements. EPA proposes to identify “heat rate improvements” (which may also be referred to as “efficiency improvements”) as the BSER for existing fossil-fuel fired steam generating EGUs. The basis for this determination is discussed below. A discussion of other potential CO 2 reduction measures that EPA has determined are not BSER (but which states may allow sources to use for compliance purposes) is also provided below. The U.S. fleet of existing coal-fired EGUs is a diverse group of units with unique individual characteristics, spread across the country. Coal-fired power plants are customized facilities that were designed and built to meet local and regional electricity needs over the past 100 years, with no two plants being identical. Geography and elevation, unit size, coal type, pollution controls, cooling system, firing method and utilization rate are just a few of the parameters that can impact the overall efficiency and performance of individual units. As a result, heat rates of existing coal-fired EGUs in the U.S. vary substantially. The variation in heat rates among EGUs with similar design characteristics, as well as year-to-year variation in heat rate at individual EGUs, indicate that there is potential for HRIs that can improve CO 2 emission performance for the existing coal-fired EGU fleet, but that this potential may vary considerably at the unit level. EPA does not currently have sufficient information on adequately demonstrated systems of emission reduction—including HRI opportunities—for existing natural gas-fired stationary combustion turbines. As such, the Agency is currently unable to determine the BSER for such units. In this action, EPA solicits information on adequately demonstrated systems of GHG emission reduction for such units—especially on the efficiency, applicability, and cost of such systems (Comment C-5). This is discussed in greater detail below. B. HRIs for Steam-Generating EGUs As mentioned above, EPA proposes in ACE to identify “heat rate improvements” as the BSER for existing steam generating fossil fuel-fired EGUs. Heat rate is a measure of efficiency that is commonly used in the power sector. The heat rate is the amount of energy input, measured in British thermal units (Btu), required to generate one kilowatt-hour (kWh) of electricity. The lower an EGU's heat rate, the more efficiently it operates. As a result, an EGU with a lower heat rate will consume less fuel per kWh generated and emit lower amounts of CO 2 and other air pollutants per kWh generated as compared to a less efficient unit. An EGU's heat rate can be affected by a variety of design characteristics, site-specific factors, and operating conditions, including: • Thermodynamic cycle of the boiler; • Boiler and steam turbine size and design; • Cooling system type; • Auxiliary equipment, including pollution controls; • Operations and maintenance practices; • Fuel quality; and • Ambient conditions. In the CPP, EPA quantified emission reductions achievable through heat rate improvements on a regional basis ( i.e., building block 1). The Agency concluded that EGUs can achieve on average a 4.3 percent improvement in the Eastern Interconnection, a 2.1 percent improvement in the Western Interconnection and a 2.3 percent improvement in the Texas Interconnection. See 80 FR 64789. The Agency then applied all three of the building blocks to 2012 baseline data and quantified, in the form of CO 2 emission rates, the reductions achievable in each interconnection in 2030 and selected the least stringent as a national performance rate. Id. at 64811-819. EPA noted that building block 1 measures could not by themselves constitute the BSER because of a potential “rebound effect.” 17 Id. at 64787. 17 As discussed below, EPA modeled a range of potential HRIs for ACE and the Agency's analysis indicates that system-wide emission decreases from heat rate improvements will likely outweigh any potential system-wide emission increases. Accordingly, EPA proposes to conclude that the “rebound effect” does not preclude a determination that HRIs constitute the BSER. EPA believes that building block 1, as constructed in CPP, does not represent an appropriate BSER, and ACE better reflects important changes in the formulation and application of the BSER in accordance with the CAA. For example, the percent improvement applied as the BSER under CPP was determined at the interconnect-level, and did not take into account remaining useful life or other source-specific factors, which are addressed in this proposed rule. 18 The current fleet of existing fossil fuel-fired EGUs is quite diverse in terms of size, age, fuel type, operation ( e.g., baseload, cycling), boiler type, etc. Many coal-fired EGUs now operate under load-following and cycling conditions as opposed to the steady baseload operating conditions that were more common a decade ago. 18 The Agency solicits comments, nonetheless, on whether and how to retain building block 1 in lieu of the proposed approach. There are available technologies and equipment upgrades, as well as best operating and maintenance practices, that EGU owners or operators may utilize to improve an EGU's heat rate. In the ANPRM, EPA solicited information on a number of technology and equipment upgrades and good practices (specifically including, but not limited to, those that were listed in Tables 1 and 2 of the ANPRM, see 82 FR 61514) that have the potential to reduce an EGU's heat rate. Specifically, the Agency solicited information on: (1) Potential HRIs from technologies and best operating and maintenance practices; (2) costs of deploying the technologies and the best operating and maintenance practices, including applicable planning, capital and operating and maintenance costs; (3) owner and operator experiences deploying the technologies and employing best operating and maintenance practices; (4) barriers to or from deploying the technologies and operating and maintenance practices; and (5) any other technologies or operating and maintenance practices that may exist for improving heat rate, but were not listed in the ANPRM. EPA received useful information in the comments submitted in response to the ANPRM. Many commenters contended that any evaluation of the HRI potential of the coal-fired EGU fleet must be done on a unit-by-unit basis since the opportunities for HRI are source-specific and dependent upon the individual unit's design, configuration, and operating and maintenance history. Many commenters emphasized the significant influence that the operating mode ( i.e., whether the unit operates at consistent baseload conditions or in cycling or load-following mode or as a low capacity factor unit that is subject to frequent startups and shutdowns) has on an individual EGU's heat rate and HRI potential. Many commenters also claimed that owners and operators of fossil fuel-fired EGUs already routinely conduct HRI efforts and, as a result, there are relatively few economic improvement opportunities available. 1. Potential HRI Measures—Technologies and Equipment Upgrades As mentioned above, numerous technologies and equipment upgrades, as well as best operating and maintenance practices (which are discussed in the next section), have been identified as potential measures to improve an EGU's heat rate. In the ANPRM, EPA solicited information on a large number of technology and equipment upgrades and best operating and maintenance practices that have the potential to reduce an EGU's heat rate. See Tables 1 and 2 of the ANPRM, 82 FR 61514. In this action, EPA is proposing to determine that heat rate improvement is the BSER for affected existing coal-fired EGUs and is proposing a list of “candidate technologies” of HRI measures for states to use in establishing standards of performance under CAA section 111(d)(1). States can use the information that EPA provides on the “degree of emission limitation achievable through application of the [BSER]” to establish standards of performance for affected EGUs covered by a state's plan. 19 While a large number of HRI measures have been identified in a variety of studies conducted by government agencies and outside groups ( see Table 3 in ANPRM, 82 FR 61515), some of those identified technologies have limited applicability and many provide only negligible HRI. EPA believes that it would be overly burdensome to require States to evaluate the degree of emission limitation achievable from the application of every single identified HRI measure—including those with negligible benefits—at each source (or subcategory of sources) within their borders. Therefore, EPA has identified a list of the “most impactful” HRI measures that we are proposing to serve as technologies, equipment upgrades and best operating and maintenance practices that form the list of “candidate technologies” constituting the BSER. The candidate technologies of the BSER is listed in Table 1 below. Best operating and maintenance practices are discussed in the next section. States are expected to evaluate each of the BSER HRI measures in the candidate technologies in establishing a standard of performance for any particular source. The States, in applying a standard of performance, may take into consideration, among other factors, the remaining useful life of the existing source to which the standard would apply. EPA solicits comments on whether other unlisted HRI measures should also be included as part of the BSER and added to the candidate technologies (Comment C-6). EPA also solicits comment on each of the candidate technologies described further below, including whether any additional technologies should be added to the list, and whether there is additional information that EPA should be aware of and consider in determining the BSER and establishing the candidate technologies for HRI measures (Comment C-7). 19 The states, in applying the unit-specific standard, may also take into consideration, among other factors, the remaining useful life of the existing source to which the standard applies. See CAA section 111(d)(1). The technologies and operating and maintenance practices listed and described below may not be available or appropriate for all types of EGUs; and some owners or operators will have already deployed some of the technologies and employed some of the best operating and maintenance practices. Table 1—Summary of Most Impactful HRI Measures and Range of Their HRI Potential (%) by EGU Size HRI measure <200 MW Min Max 200-500 MW Min Max >500 MW Min Max Neural Network/Intelligent Sootblowers 0.5 1.4 0.3 1.0 0.3 0.9 Boiler Feed Pumps 0.2 0.5 0.2 0.5 0.2 0.5 Air Heater & Duct Leakage Control 0.1 0.4 0.1 0.4 0.1 0.4 Variable Frequency Drives 0.2 0.9 0.2 1.0 0.2 1.0 Blade Path Upgrade (Steam Turbine) 0.9 2.7 1.0 2.9 1.0 2.9 Redesign/Replace Economizer 0.5 0.9 0.5 1.0 0.5 1.0 Improved O&M Practices Can range from 0 to >2.0% depending on the unit's historical O&M practices. a. Neural Network/Intelligent Sootblower Neural networks. Computer models, known as neural networks, can be used to simulate the performance of the power plant at various operating loads. Typically, the neural network system ties into the plant's distributed control system for data input (process monitoring) and process control. The system uses plant specific modeling and control modules to optimize the unit's operation and minimize the emissions. This model predictive control can be particularly effective at improving the plants performance and minimizing emissions during periods of rapid load changes. The neural network can be used to optimize combustion conditions, steam temperatures, and air pollution control equipment. Intelligent Sootblowers. During operations at a coal-fired power plant, particulate matter (ash or soot) builds up on heat transfer surfaces. This build-up degrades the performance of the heat transfer equipment and negatively affects the efficiency of the plant. Power plant operators use steam injection “sootblowers” to clean the heat transfer surfaces by removing the ash build-up. This is often done on a routine basis or as needed based on monitored operating characteristics. Intelligent sootblowers (ISB) are automated systems that use process measurements to monitor the heat transfer performance and strategically allocate steam to specific areas to remove ash buildup. The cost to implement an ISB system is relatively inexpensive if the necessary hardware is already installed. The ISB software/control system is often incorporated into the neural network software package mentioned above. As such, the HRIs obtained via installation of neural network and ISB systems are not necessarily cumulative. The efficiency improvements from installation of intelligent sootblowers are often greatest for EGUs firing subbituminous coal and lignite due to more significant and rapid fouling at those units as compared to EGUs firing bituminous coal. b. Boiler Feed Pumps A boiler feed pump (or boiler feedwater pump) is a device used to pump feedwater into a boiler. The water may be either freshly supplied or returning condensate produced from condensing steam produced by the boiler. The boiler feed pumps consume a large fraction of the auxiliary power used internally within a power plant. Boiler feed pumps can require power in excess of 10 MW on a 500-MW power plant. Therefore, the maintenance on these pumps should be rigorous to ensure both reliability and high-efficiency operation Boiler feed pumps wear over time and subsequently operate below the original design efficiency. The most pragmatic remedy is to rebuild a boiler feed pump in an overhaul or upgrade. c. Air Heater and Duct Leakage Control The air pre-heater is a device that recovers heat from the flue gas for use in pre-heating the incoming combustion air (and potentially for other uses such as coal drying). Properly operating air pre-heaters play a significant role in the overall efficiency of a coal-fired EGU. A major difficulty associated with the use of regenerative air pre-heaters is air leakage from the combustion air side to the flue gas side. Air leakage affects boiler efficiency due to lost heat recovery and affects the axillary load since any leakage requires additional fan capacity. The amount of air leaking past the seals tends to increase as the unit ages. Improvements to seals on regenerative air pre-heaters have enabled the reduction of air leakage. d. Variable Frequency Drives (VFDs) VFD on ID Fans. The increased pressure required to maintain proper flue gas flow through add-on air pollutant control equipment may require additional fan power, which can be achieved by an induced draft (ID) fan upgrade/replacement or an added booster fan. Generally, older power plant facilities were designed and built with centrifugal fans. The most precise and energy-efficient method of flue gas flow control is use of VFD. The VFD controls fan speed electrically by using a static controllable rectifier (thyristor) to control frequency and voltage and, thereby, the fan speed. The VFD enables very precise and accurate speed control with an almost instantaneous response to control signals. The VFD controller enables highly efficient fan performance at almost all percentages of flow turndown. Due to current electricity market conditions, many units no longer operate at base-load capacity and, therefore, VFDs, also known as variable-speed drives on fans can greatly enhance plant performance at off-peak loads. Additionally, because utilities are phasing in their environmental equipment upgrades, new fans are oversized and operated at lower capacities until all additional equipment has been added. Under these scenarios, VFDs can significantly improve the unit heat rate. VFDs as motor controllers offer many substantial improvements to electric motor power requirements. The drives provide benefits such as soft starts, which reduce initial electrical load, excessive torque, and subsequent equipment wear during startups; provide precise speed control; and enable high-efficiency operation of motors at less than the maximum efficiency point. During load turndown, plant auxiliary power could be reduced by 30-60 percent if all large motors in a plant were efficiently controlled by VFD. With unit loads varying throughout the year, the benefits of using VFDs on large-size equipment, such as FD or ID fans, boiler feedwater and condenser circulation water pumps, can have significant impacts. Because plants today usually use either new booster ID fans or new ID fans, the option of investing in VFDs generally appeals to plant operators since they are incurring long outages to install the either new or additional air emission controls equipment. There are circumstances in which the HRI has been estimated to be much higher than that shown in Table 1, depending on the operation of the unit. Cycling units realize the greatest gains representative of the upper range of HRI, whereas units which were designed with excess fan capacity will exhibit the lower range. VFD on Boiler Feed Pumps. VFDs can also be used on boiler feed water pumps as mentioned previously. Generally, if a unit with an older steam turbine is rated below 350 MW the use of motor-driven boiler feedwater pumps as the main drivers may be considered practical from an efficiency standpoint. If a unit cycles frequently then operation of the pumps with VFDs will offer the best results on heat rate reductions, followed by fluid couplings. The use of VFDs for boiler feed pumps is becoming more common in the industry for larger units. And with the advancements in low pressure steam turbines, a motor-driven feed pump can improve the thermal performance of a system up to the 600-MW range, as compared to the performance associated with the use of turbine drive pumps. Smaller and older units will generally not upgrade to a VFD boiler feed pump drive due to high capital costs. e. Blade Path Upgrade (Steam Turbine) Upgrades or overhauls of steam turbines offer the greatest opportunity for HRI on many units. Significant increases in performance can be gained from turbine upgrades when plants experience problems such as steam leakages or blade erosion. The typical turbine upgrade depends on the history of the turbine itself and its overall performance. The upgrade can entail myriad improvements, all of which affect the performance and associated costs. The availability of advanced design tools, such as computational fluid dynamics (CFD), coupled with improved materials of construction and machining and fabrication capabilities have significantly enhanced the efficiency of modern turbines. These improvements in new turbines can also be utilized to improve the efficiency of older steam turbines whose efficiency has degraded over time. Upgrades or overhauls of steam turbines may offer the greatest opportunity for HRI on many units. Significant increases in performance can be gained from turbine upgrades when plants experience problems such as steam leakages or blade erosion. The typical turbine upgrade depends on the history of the turbine itself and its overall performance. The upgrade can entail myriad improvements, all of which affect the performance and associated costs. f. Redesign/Replace Economizer In steam power plants, economizers are heat exchange devices used to capture waste heat from boiler flue gas which is then used to heat the boiler feedwater. This use of waste heat reduces the need to use extracted energy from the system and, therefore, improves the overall efficiency or heat rate of the unit. As with most other heat transfer devices, the performance of the economizer will degrade with time and use, and power plant representatives contend that economizer replacements are often delayed or avoided due to concerns about triggering NSR requirements. In some cases, economizer replacement projects have been undertaken concurrently with retrofit installation of selective catalytic reduction (SCR) systems because the entrance temperature for the SCR unit must be controlled to a specific range. 2. Potential HRI Measures—Best Operating and Maintenance Practices Many unit operators can achieve additional HRI by adopting best operating and maintenance practices. The amount of achievable HRI will vary significantly from unit to unit. In setting a standard of performance for a specific unit or subcategory of units, states should consider the opportunities for HRI from the following actions. a. Adopt HRI Training for O&M Staff EGU operators can obtain HRI by adopting “awareness training” to ensure that all O&M staff are aware of best practices and how those practices affect the unit's heat rate. b. Perform On-Site Appraisals To Identify Areas for Improved Heat Rate Performance Some large utilities have internal groups that can perform on-site evaluations of heat rate performance improvement opportunities. Outside ( i.e., third party) groups can also provide site-specific/unit-specific evaluations to identify opportunities for HRI. c. Improved Steam Surface Condenser—Cleaning Effective operation of the steam surface condenser in a power plant can significantly improve a unit's heat rate. In fact, in many cases it can pose the most significant hindrance to a plant trying to maintain its original design heat rate. Since the primary function of the condenser is to condense steam flowing from the last stage of the steam turbine to liquid form, it is most desirable from a thermodynamic standpoint that this occurs at the lowest temperature reasonably feasible. By lowering the condensing temperature, the backpressure on the turbine is lowered, which improves turbine performance. Condenser Cleaning. A condenser degrades primarily due to fouling of the tubes and air in-leakage. Tube fouling leads to reduced heat transfer rates, while air in-leakage directly increases the backpressure of the condenser and degrades the quality of the water. Condenser tube cleaning can be performed using either on-line methods or more rigorous off-line methods. A full economic analysis should be performed to determine which off-line cleaning method is to be used. Such an analysis would result in an optimum offline or reduced-load cleaning schedule that could average between two and three cleanings a year. These analyses consider inputs such as operating data, plant performance, loads, time of year, etc., to accurately assess cleaning schedules for optimum economic performance. 3. Cost of HRI a. Reasonableness of Cost As mentioned earlier, under CAA section 111(a)(1), EPA is required to determine “the best system of emission reduction which (taking into account the cost . . .) . . . has been adequately demonstrated.” In several cases, the D.C. Circuit has elaborated on this cost factor in various ways, stating that EPA may not adopt a standard for which costs would be “exorbitant,” 20 “greater than the industry could bear and survive,” 21 “excessive,” 22 or “unreasonable.” 23 These formulations appear to be synonymous and suggest a cost-reasonableness standard. Therefore, in this action, EPA has evaluated whether the costs of HRI are considered to be reasonable. 20 Lignite Energy, 198 F.3d at 933. 21 Portland Cement, 513 F.2d at 508. 22 Sierra Club, 657 F.2d at 343. 23 Id. Any efficiency improvement made by an EGU will also reduce the amount of fuel consumed per unit of electricity output; fuel costs can account for as much as 70 percent of production costs of power. The cost attributable to CO 2 emission reductions, therefore, is the net cost of achieving HRIs after any savings from reduced fuel expenses. So, over some time period (depending upon, among other factors, the extent of HRIs, the cost to implement such improvements, and the unit utilization rate), the savings in fuel cost associated with HRIs may be sufficient to cover the costs of implementing the HRI measures. Thus, the net costs of HRIs associated with reducing CO 2 emissions from affected EGUs can be relatively low depending upon each EGUs' individual circumstances. It should be noted that this cost evaluation is not an attempt to determine the affordability of the HRI in a business or economic sense ( i.e., the reasonableness of the imposed cost is not determined by whether there is an economic payback within a predefined time period). However, the ability of EGUs to recoup some of the costs of HRIs through fuel savings supports a finding that cost recovery is a reasonable factor in determining cost effectiveness. 24 24 While some EGUs may not realize the full potential of cost recuperation from fuel savings, we expect that the net costs of implementing heat rate improvements as an approach to reducing CO 2 emissions from fossil fuel-fired EGUs are reasonable. Most often, when evaluating costs for criteria pollutants—in a BACT analysis, for example—the emphasis is focused on the cost of control relative to the amount of pollutant removed—a metric typically referred to as the “cost-effectiveness.” There have been relatively few BACT analyses evaluating GHG reduction technologies for coal-fired EGUs; and, therefore not a large number of GHG cost-effectiveness determinations to compare against as a measure of the cost reasonableness. Nevertheless, in PSD and Title V permitting guidance for GHG emissions, EPA noted that “it is important in BACT reviews for permitting authorities to consider options that improve the overall energy efficiency of the source or modification—through technologies, processes and practices at the emitting unit. In general, a more energy efficient technology burns less fuel than a less energy efficient technology on a per unit of output basis.” 25 EPA has also noted that a “number of energy efficiency technologies are available for application to both existing and new coal-fired EGU projects that can provide incremental step improvements to the overall thermal efficiency.” 26 25 See page 21, “PSD and Title V Permitting Guidance for Greenhouse Gases,” EPA-457/B-11-001, March 2011; https://www.epa.gov/sites/production/files/2015-12/documents/ghgpermittingguidance.pdf . 26 See page 25, “Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-fired Electric Generating Units,” October 2010; https://www.epa.gov/sites/production/files/2015-12/documents/electricgeneration.pdf . b. Cost of the HRI Candidate Technologies Measures The estimated costs for the BSER candidate technologies are presented below in Table 2. These are cost ranges from the 2009 S&L Study 27 updated to $2016. These costs correspond to ranges of HRI (percent) presented earlier in Table 1. 27 “Coal-Fired Power Plant Heat Rate Reductions” Sargent & Lundy report SL-009597 (2009) https://www.epa.gov/sites/production/files/2015-08/documents/coalfired.pdf . Table 2—Summary of Cost ($2016/kW) of HRI Measures HRI measure <200 MW Min Max 200-500 MW Min Max >500 MW Min Max Neural Network/Intelligent Sootblowers 4.7 4.7 2.5 2.5 1.4 1.4 Boiler Feed Pumps 1.4 2.0 1.1 1.3 0.9 1.0 Air Heater & Duct Leakage Control 3.6 4.7 2.5 2.7 2.1 2.4 Variable Frequency Drives 9.1 11.9 7.2 9.4 6.6 7.9 Blade Path Upgrade (Steam Turbine) 11.2 66.9 8.9 44.6 6.2 31.0 Redesign/Replace Economizer 13.1 18.7 10.5 12.7 10.0 11.2 Improved O&M Practices Minimal capital cost. In the CPP, EPA estimated the potential national average net HRI by coal-fired EGUs to between 2.1 to 4.3 percent for each interconnection, or about 4 percent nationally, with the improvements coming from some combination of best operating practices and equipment upgrades. The Agency noted in the CPP that the maximum cost of HRI from Table 2 is expected to be less than the $100/kW value used in the CPP proposal, especially as the EGU size increases; and, therefore, the Agency assessed the economic effects of HRI costs that might range from $50 to $100/kW. The technical applicability and efficacy of HRI measures and the cost of implementing them are dependent upon site specific factors and can vary widely from site to site. Because there is inherent flexibility provided to the states in applying the standards of performance, there is a wide range of potential outcomes that are highly dependent upon how the standards are applied (and to what degree states take into consideration other factors, including remaining useful life). In the RIA accompanying this proposal, the Agency evaluates three illustrative scenarios that recognize the inherent flexibility provided to states in applying standards of performance and provide insight on potential outcomes. For those illustrative scenarios, EPA evaluates costs ranging from $50/kW to $100/kW. EPA requests comment, with analysis, on other cost ranges that may be appropriate. 4. Nonair Quality Health and Environmental Impacts, Energy Requirements, and Other Considerations As directed by CAA section 111(a)(1), EPA has taken into account nonair quality health and environment requirements, and energy requirements for each of the candidate BSER technologies listed in Tables 1 and 2. None of the candidate technologies, if implemented at a coal-fired EGU, would be expected to result in any deleterious effects on any of the liquid effluents ( e.g., scrubber liquor) or solid by-products ( e.g., ash, scrubber solids). All of these candidate technologies, when implemented, would have the effect of improving the efficiency of the coal-fired EGUs to which they are applied. As such, the EGU would be expected to use less fuel to produce the same amount of electricity as it did prior to the efficiency (heat rate) improvement. None of candidate technologies is expected to impose any significant additional auxiliary energy demand. Implementation of heat rate improvement measures also would achieve reasonable reductions in CO 2 emissions from affected sources in light of the limited cost-effective and technically feasible emissions control opportunities. In the same vein, because existing sources face inherent constraints that new sources do not, existing sources present different, and in some ways more limited, opportunities for technological innovation or development. Nevertheless, the proposed emissions guidelines encourage technological development by promoting further development and market penetration of equipment upgrades and process changes that improve plant efficiency. 5. Potential HRI at Existing Coal-Fired EGUs Government agencies and laboratories, industry research organizations, engineering firms, equipment suppliers, and environmental organizations have conducted studies examining the potential for improving heat rate in the U.S. EGU fleet or a subset of the fleet. Table 3 below provides a list of some reports, case studies, and analyses about HRI opportunities in the United States. EPA is seeking comment on how these studies (and any others that the Agency should be aware of) can inform our understanding of potential HRI opportunities (Comment C-8). Table 3—HRI Reports, Case Studies, and Analyses HRI report organization/publication (author, if known)—title—year [URL] Government Studies: Congressional Research Service (Campbell)—Increasing the Efficiency of Existing Coal-fired Power Plants (R43343)—2013 [ https://fas.org/sgp/crs/misc/R43343.pdf ]. EIA—Analysis of Heat Rate Improvement Potential at Coal-Fired Power Plants—2015 [ https://www.eia.gov/analysis/studies/powerplants/heatrate/pdf/heatrate.pdf ]. EPA—Greenhouse Gas Mitigation Measures—2015 [ https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-37114 ]. NETL—Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants—2009 [ http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/OpportImproveEfficExistCFPP-ReportFinal.pdf ]. NETL—Improving the Thermal Efficiency of Coal-Fired Power Plants in the United States—2010 [ http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/ThermalEfficCoalFiredPowerPlants-TechWorkshopRpt.pdf ]. NETL—Improving the Efficiency of Coal-Fired Power Plants for Near Term Greenhouse Gas Emissions Reductions (DOE/NETL-2010/1411)—2010 [ http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2010-1411-ImpEfficCFPPGHGRdctns-0410.pdf ]. NETL—Options for Improving the Efficiency of Existing Coal-Fired Power Plants (DOE/NETL-2013/1611)—2014 [ https://www.netl.doe.gov/energy-analyses/temp/FY14_OptionsforImprovingtheEfficiencyofExistingCoalFiredPowerPlants_040114.pdf ]. IEA (Reid)—Retrofitting Lignite Plants to Improve Efficiency and Performance (CCC/264)—2016 [ http://bookshop.iea-coal.org/reports/ccc-264/83861 ]. IEA (Henderson)—Upgrading and Efficiency Improvement in Coal-fired Power Plants (CCC/221)—2013 [ http://bookshop.iea-coal.org/reports/ccc-221/83186 ]. European Commission—Integrated Pollution Prevention and Control Reference Document on Best Available Techniques for Large Combustion Plants—2006 [ http://eippcb.jrc.ec.europa.eu/reference/BREF/lcp_bref_0706.pdf ]. Industry/Industrial Groups: EPRI—Range of Applicability of Heat Rate Improvements—2014 [ https://www.epri.com/#/pages/product/000000003002003457 ]. ABB Power Generation—Energy Efficient Design of Auxiliary Systems in Fossil-Fuel Power Plants [ https://library.e.abb.com/public/5e627b842a63d389c1257b2f002c7e77/Energy%20Efficiency%20for%20Power%20Plant%20Auxiliaries-V2_0.pdf ]. Alstom Engineering (Sutton)—CO 2 Reduction Through Energy Efficiency in Coal-Fired Boilers—2011 [ http://www.mcilvainecompany.com/Universal_Power/Subscriber/PowerDescriptionLinks/Jim%20Sutton%20-%20Alstom%20-%203-31-2011.pdf ]. GE—Comments of the General Electric Company—2014 [ https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22971 ]. National Petroleum Council—Electric Generation Efficiency—2007 [ http://www.npc.org/Study_Topic_Papers/4-DTG-ElectricEfficiency.pdf ]. S&L—Coal-fired Power Plant Heat Rate Reductions (SL-009597)—2009 [ https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-36895 ]. S&L—Coal Fired Power Plant Heat Rate Reduction—NRECA (SL-012541)—2014 [ https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0602-22767 Supp 33 ]. Storm Technologies—Applying the Fundamentals for Best Heat Rate Performance of Pulverized Coal Fueled Boilers—2009 [ http://www.stormeng.com/pdf/EPRI2009HeatRateConference%20FINAL.pdf ]. Environmental Groups/Academic Studies: Lehigh University—Reducing Heat Rates of Coal-fired Power Plants—2009 [ http://www.lehigh.edu/~inenr/leu/leu_61.pdf ]. NRDC—Closing the Power Plant Carbon Pollution Loophole: Smart Ways the Clean Air Act Can Clean Up America's Biggest Climate Polluters (12-11-A)—2013 [ https://www.nrdc.org/sites/default/files/pollution-standards-report.pdf ]. Resources for the Future (Lin et al. )—Regulating Greenhouse Gases from Coal Power Plants Under the Clean Air Act (RFF-DP-13-05)—2014 [ http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-DP-13-05.pdf ]. Sierra Club (Buckheit & Spiegel)—Sierra Club 52 Unit Study—2014 [ http://content.sierraclub.org/environmentallaw/sites/content.sierraclub.org.environmentallaw/files/Appendix%201%20-%20Rate%20v%20Load%20Summary.pdf ]. Other Publications: Power Engineering International (Co X )—Dry Sorbent Injection for SO X Emissions Control—2017 [ http://www.powerengineeringint.com/articles/print/volume-25/issue-6/features/dry-sorbent-injection-for-sox-emissions-control.html ]. Power Mag (Korellis)—Coal-Fired Power Plant Heat Rate Improvement Options, Parts 1 & 2—2014 [ http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-2 ] [ http://www.powermag.com/coal-fired-power-plant-heat-rate-improvement-options-part-1 ]. Power Mag (Peltier)—Steam Turbine Upgrading: Low-hanging Fruit—2006 [ http://www.powermag.com/steam-turbine-upgrading-low-hanging-fruit ]. It has been noted that unit-level HRIs, with the resulting reductions in variable operating costs at those improved EGUs, could lead to increases in utilization of those EGUs as compared to other generating options ( i.e., “rebound effect”). See generally 80 FR 64745. As part of the cost-benefit analysis in the RIA for this proposed action, EPA modeled a range of potential HRIs (percent improvement, as described in the RIA). The results of the modeling, for the years of analysis for this rule, predict that there will be no cumulative increases in system-wide emissions relative to a scenario where no action is taken. While the RIA shows that, under certain assumptions, sources that adopt HRI may increase generation, due to their improved efficiency and relatively improved economic competitiveness, they also generally reduce emissions (as a group) because they can generate higher levels of electricity with a lower overall emission rate. Hence, EPA analysis indicates that the system-wide emission decreases due to reduced heat rate are likely to be larger than any system-wide increases due to increased operation. EPA solicits comment on this conclusion (Comment C-9). C. HRI for Natural Gas-Fired Stationary Combustion Turbines EPA has also considered opportunities for emission reductions at natural gas-fired stationary combustion turbines as a part of the BSER—at both simple cycle turbines and combined cycle turbines—and previously determined that the available emission reductions would likely be expensive or would likely provide only small overall reductions relative to those that were predicted through application of other systems of emission reduction identified in the CPP building blocks. In the development of the CAA section 111(b) standards of performance for new, modified, and reconstructed EGUs, several commenters provided information on options that may be available to improve the efficiency of existing natural gas-fired stationary combustion turbines. See 80 FR 64620. Commenters—including turbine manufacturers—described specific technology upgrades for the compressor, combustor, and gas turbine components that operators of existing combustion turbines may deploy. The commenters noted that these state-of-the-art gas path upgrades, software upgrades, and combustor upgrades have the potential to reduce GHG emissions by a significant amount. In addition, one turbine manufacturer stated that existing combustion turbines can achieve the largest efficiency improvements by upgrading existing compressors with more advanced compressor technologies, potentially improving the combustion turbine's efficiency by an additional margin. See 80 FR 64620. In addition to upgrades to the combustion turbine, the operator of a NGCC unit may have the opportunity to improve the efficiency of the heat recovery steam generator and steam cycle using retrofit technologies that may reduce the GHG emissions by 1.5 to 3 percent. These include: (1) Steam path upgrades that can minimize aerodynamic and steam leakage losses; (2) replacement of the existing high-pressure turbine stages with state-of-the-art stages capable of extracting more energy from the same steam supply; and (3) replacement of low-pressure turbine stages with larger diameter components that extract additional energy and that reduce velocities, wear, and corrosion. In the ANPRM, EPA requested comment on the broad availability and applicability of any HRIs for natural gas combustion turbine EGUs. EPA also solicited comment on the Agency's previous determination in the CPP that the available GHG emission reduction opportunities would likely provide only small overall GHG reductions as compared to those from HRIs at existing coal-fired EGUs. See 80 FR 64756. Several commenters suggested that there are significant opportunities for emission reductions via HRIs at natural gas combined cycle EGUs while many other commenters contended that any such emission reductions would be minimal and too expensive. Still, other commenters noted that operational changes—such as lower capacity factor or fluctuations in load (cycling)—affect the heat rate and make it difficult to accurately gauge the availability of HRI opportunities for NGCC EGUs. However, while numerous comments suggested that there are available HRI opportunities at existing NGCC EGUs, no commenters provided specific information on the availability, applicability, or cost of HRI opportunities for NGCC units—nor did any commenters provide any information on the magnitude of expected heat rate reductions. To assess potential HRI of existing NGCC EGUs, EPA looked at 11 years of historical gross heat rate data from 2007 to 2017 for existing NGCC EGUs that reported both heat input and gross electricity output to the Agency in 2017. The Agency used the 2007 to 2016 data to calculate a “benchmark” heat rate for each unit. EPA evaluated the HRI potential using an approach that is similar to the method used to determine a unit-specific standard that was finalized for modified coal-fired EGUs. The Agency evaluated the HRI potential by comparing the 2017 national annual heat rate with the best annual heat rate in the years from 2007 to 2016 year. The HRI potential was calculated nationally and at each regional interconnection: East, West, and Texas. Nationally the HRI evaluation suggested an average HRI potential of 3.4 percent. EPA also conducted a literature search and found some papers suggesting potential for improvement in the heat rate. The literature suggested that most HRIs would be accompanied by commensurate capacity increases. 28 EPA takes comment on the estimates in this paper and is seeking any other information commenters have about the performance and cost of potential HRIs for turbines (Comment C-10). We also take comment on whether if EPA determined that HRIs in that range were available for similar costs, it would be appropriate for EPA to reconsider its determination that there are no HRIs that represent the BSER (Comment C-11). 28 Phillips, J.; Levine, P.; “Gas Turbine Performance Upgrade Options”, FERN Engineering Paper, available at http://www.fernengineering.com/pdf/gt_upgrade_options.pdf. D. Other Considered Systems of GHG Emission Reductions EPA also considered other systems of GHG emission reductions that may be applied to affected EGUs but is not proposing that they should be part of the BSER for the reasons discussed below. EPA acknowledges that there may be other methods and technologies suitable for adoption at some specific sources, but states and sources are best suited to determine if those alternative measures and technologies are appropriate and/or allowable compliance measures. 1. Carbon Capture and Storage (CCS) 29 EPA has previously determined that CCS (or partial CCS) should not be a part of the BSER for existing fossil fuel-fired EGUs because it was significantly more expensive than alternative options for reducing emissions and may not be a viable option for many individual facilities. See 80 FR 64756. Even assuming that CAA section 111(d) may be used to project technological advances, EPA must balance innovative technologies against their economic, energy, nonair health and environmental impacts. EPA continues to believe that neither CCS nor partial CCS are technologies that can be considered the BSER for existing fossil fuel-fired EGUs. However, if there is any new information regarding the availability, applicability, costs, or technical feasibility of CCS technologies, commenters are encouraged to provide that information to EPA (Comment C-12). 29 CCS is sometimes referred to as Carbon Capture and Sequestration. It is also sometimes referred to as CCUS or Carbon Capture Utilization and Storage (or Sequestration), where the captured CO 2 is utilized in some useful way and/or permanently stored (for example, in conjunction with enhanced oil recovery). In this document, we consider these terms to be interchangeable and for convenience will exclusively use the term CCS. Similarly, EPA considered whether CCS or partial CCS should be the BSER for natural gas-fired stationary combustion turbines and have determined that, currently, the technology is exorbitantly expensive, has not been adequately demonstrated, and would not be available for a large number of existing sources. Similar technologies—such as use of the novel Allam Cycle 30 —are, while seemingly promising, still in the early demonstration phase. 30 https://www.netpower.com/. 2. Fuel Co-Firing EPA has previously determined that co-firing of alternative fuels (biomass or natural gas) in coal-fired utility boilers is not part of BSER for existing fossil fuel-fired sources due to cost and feasibility considerations. See 80 FR 64756. Although some fuel co-firing methods are technically feasible for some affected sources, there are factors and considerations that prevent its inclusion as BSER. In general, fuel use opportunities are dependent upon many regional considerations and characteristics ( e.g., access to biomass, or natural gas pipeline infrastructure limitations), that prevent its adoption as BSER on a national level (whereas nearly all sources can or have implemented some form of heat rate improvement measures). Another important factor is cost, and broader application of fuel co-firing methods has been shown to be costly. While this proposal does not include fuel co-firing methods as BSER, EPA proposes that they be allowed as compliance options that states may consider (see Section VI). EPA solicits comment, nevertheless, on whether co-firing methods should be included among the list of BSER candidate technologies for states to evaluate when establishing a standard of performance for each affected source in their jurisdiction. a. Natural Gas Co-Firing Coal-fired power plants typically use natural gas or other clean fuel (such as low sulfur fuel oil) for start-up operations and, if needed, to maintain the unit in “warm stand-by.” Some plants co-fire natural gas simultaneously with coal—either directly as a combustion fuel or in configuration referred to as natural gas reburn, which is used for NOx control. During periods of natural gas co-firing, an EGU's CO 2 emission rate is reduced as natural gas is a less carbon intensive fuel than coal. For example, at 10 percent natural gas co-firing, the net emissions rate (lb/MWh-net) of a typical unit would decrease by approximately 4 percent. On the other hand, co-firing can negatively impact a unit's efficiency due to the high hydrogen content of natural gas and the resulting production of water as a combustion by-product. And depending on the design of the boiler and extent of modifications, some boilers may be forced to de-rate (a reduction in generating capacity) in order to maintain steam temperatures at or within design limits, or for other technical reasons. In evaluating BSER technology options, CAA section 111(a)(1) directs EPA to take into account nonair quality health and environmental impacts, and energy requirements. EPA is unaware of any significant nonair quality health or environmental impacts associated with natural gas co-firing. However, in taking energy requirements into account, EPA notes that co-firing natural gas in coal-fired utility boilers is not the best, most efficient use of natural gas and, as noted above, can lead to inefficient operation of utility boilers. NGCC stationary combustion turbine units are much more efficient at using natural gas as a fuel for the production of electricity and it would not be an environmentally positive outcome for utilities and owner/operators to redirect natural gas from the more efficient NGCC EGUs to the less efficient coal-fired EGUs in order to satisfy an emission standard at the coal-fired unit. Moreover, unlike coal, natural gas cannot be stored in quantities sufficient for sustained utilization on site. Accordingly, delivery of natural gas via pipeline is essential for using natural gas at coal-fired EGUs. Many existing coal-fired plants, however, do not have access to natural gas transportation infrastruct [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%3A2018-18755. Public record. Not legal advice.