National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units-Subcategory of Certain Existing Electric Utility Steam Generating Units Firing Eastern Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air Pollutants, 20838-20855 [2020-07878]

Download as PDF 20838 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. See section 307(b)(2). 110(a)(2)(J) for the 2015 8-hour ozone NAAQS. EPA conditionally approved these portions of North Carolina’s September 27, 2018 infrastructure SIP submission in an action published in the Federal Register on April 15, 2020. If North Carolina fails to meet its commitment by April 15, 2021, the conditional approval will become a disapproval on that date and EPA will issue a notification to that effect. List of Subjects in 40 CFR Part 52 Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Volatile organic compounds. [FR Doc. 2020–06584 Filed 4–14–20; 8:45 am] Dated: March 17, 2020. Mary S. Walker, Regional Administrator, Region 4. 1. The authority citation for part 52 continues to read as follows: ■ Environmental Protection Agency (EPA). ACTION: Final rule. Subpart L—Georgia 2. Add § 52.569 to read as follows: Conditional approval. Subpart II— North Carolina 3. Add § 52.1769 to read as follows: jbell on DSKJLSW7X2PROD with RULES Conditional approval. North Carolina submitted a letter to EPA on December 16, 2019, with a commitment to address the State Implementation Plan deficiencies regarding the PSD-related requirements of CAA sections 110(a)(2)(C), 110(a)(2)(D)(i)(II) (Prong 3), and VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 The U.S. Environmental Protection Agency (EPA) is taking final action establishing a subcategory of certain existing electric utility steam generating units (EGUs) firing eastern bituminous coal refuse (EBCR) for acid gas hazardous air pollutant (HAP) emissions that was noticed in a February 7, 2019, proposed rule titled ‘‘National Emission Standards for Hazardous Air Pollutants: Coal- and OilFired Electric Utility Steam Generating Units—Reconsideration of Supplemental Finding and Residual Risk and Technology Review’’ (2019 Proposal). After consideration of public comments, the EPA has determined that there is a need for such a subcategory under the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired EGUs, commonly known as the Mercury and Air Toxics Standards (MATS), and the Agency is establishing acid gas HAP emission standards applicable only to the new subcategory. The EPA’s final decisions on the other two distinct actions in the 2019 Proposal (i.e., reconsideration of the 2016 Supplemental Finding that it is appropriate and necessary to regulate EGUs under Clean Air Act (CAA) SUMMARY: Georgia submitted a letter to EPA on November 14, 2019, with a commitment to address the State Implementation Plan deficiencies regarding the PSDrelated requirements of CAA sections 110(a)(2)(C), 110(a)(2)(D)(i)(II) (Prong 3), and 110(a)(2)(J) for the 2015 8-hour ozone NAAQS. EPA conditionally approved these portions of Georgia’s September 24, 2018 infrastructure SIP submission in an action published in the Federal Register on April 15, 2020. If Georgia fails to meet its commitment by April 15, 2021, the conditional approval will become a disapproval on that date and EPA will issue a notification to that effect. § 52.1769 [EPA–HQ–OAR–2018–0794; FRL–10007–26– OAR] AGENCY: Authority: 42 U.S.C. 7401 et seq. ■ 40 CFR Part 63 National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Subcategory of Certain Existing Electric Utility Steam Generating Units Firing Eastern Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air Pollutants PART 52—APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS § 52.569 ENVIRONMENTAL PROTECTION AGENCY RIN 2060–AU48 Title 40 CFR part 52 is amended as follows: ■ BILLING CODE 6560–50–P PO 00000 Frm 00028 Fmt 4700 Sfmt 4700 section 112 and the residual risk and technology review of MATS) will be announced in a separate final action. DATES: This final rule is effective on April 15, 2020. ADDRESSES: The EPA has established a docket for this action under Docket ID No. EPA–HQ–OAR–2018–0794. All documents in the docket are listed on the https://www.regulations.gov/ website. Although listed, some information is not publicly available, e.g., confidential business information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through https:// www.regulations.gov/, or in hard copy at the EPA Docket Center, Room Number 3334, WJC West Building, 1301 Constitution Ave. NW, Washington, DC. The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m., Eastern Standard Time (EST), Monday through Friday. 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. FOR FURTHER INFORMATION CONTACT: For questions about this final action, contact Mary Johnson, Sector Policies and Programs Division (D243–01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541– 5025; and email address: johnson.mary@epa.gov. For information about the applicability of the NESHAP to a particular entity, contact your EPA Regional representative as listed in 40 CFR 63.13 (General Provisions). SUPPLEMENTARY INFORMATION: Preamble acronyms and abbreviations. The EPA uses multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: ARIPPA Appalachian Region Independent Power Producers Association CAA Clean Air Act CEMS continuous emissions monitoring systems CFR Code of Federal Regulations CRA Congressional Review Act DSI dry sorbent injection EBCR eastern bituminous coal refuse ECMPS Emissions Collection and Monitoring Plan System EGU electric utility steam generating unit EPA Environmental Protection Agency FBC fluidized bed combustors E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations FGD flue gas desulfurization HAP hazardous air pollutant(s) HCl hydrochloric acid Hg mercury ICR Information Collection Request lb pound lb/MMBtu pounds per million British thermal units lb/MWh pounds per megawatt-hour MACT maximum achievable control technology MATS Mercury and Air Toxics Standards MMBtu million British thermal units MW megawatt MWh megawatt-hour NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NESHAP national emission standards for hazardous air pollutants NTTAA National Technology Transfer and Advancement Act OMB Office of Management and Budget PM particulate matter PM2.5 fine particulate matter PRA Paperwork Reduction Act RFA Regulatory Flexibility Act SDA spray dryer absorbers SO2 sulfur dioxide tpy tons per year UMRA Unfunded Mandates Reform Act jbell on DSKJLSW7X2PROD with RULES Organization of this document. The information in this preamble is organized as follows: I. General Information A. Executive Summary B. Does this action apply to me? C. Where can I get a copy of this document and other related information? D. Judicial Review and Administrative Reconsideration II. Background III. Summary of Final Action A. Basis for Subcategory B. Subcategory Emission Standards IV. Summary of Cost, Environmental, and Economic Impacts and Additional Analyses Conducted A. What are the affected sources? B. What are the air quality impacts? C. What are the compliance cost impacts? D. What are the economic impacts? E. What are the forgone benefits? V. 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 Regulations 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 VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 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 L. Congressional Review Act (CRA) I. General Information A. Executive Summary In the 2012 MATS rulemaking, the EPA established one subcategory of coal-fired EGUs for purposes of regulating acid gas HAP emissions. The Agency specifically rejected a request from some commenters for a separate acid gas HAP standard for all coal refuse-fired EGUs because we determined that the emissions of such HAP from some units combusting coal refuse were among the best performing sources for acid gas HAP as determined consistent with CAA section 112(d)(3). The EPA has reevaluated the data available when the 2012 MATS rule was established, in addition to new data generated since promulgation of that rule, and we now recognize that there are differences in the acid gas HAP emissions from EGUs firing EBCR as compared to EGUs firing other types of coal, including those firing types of coal refuse other than EBCR. Specifically, the EPA recognizes that there are differences between anthracite coal refuse and bituminous coal refuse, and that the type of fuel used leads to differences in the acid gas HAP emissions from EGUs firing those respective fuels. In the February 7, 2019 Proposal (84 FR 2670), the EPA explained that these differences in acid gas HAP emissions support the establishment of a subcategory for such sources and solicited comment on the need to establish a subcategory of certain existing EGUs firing EBCR for acid gas HAP emissions and on potential emissions standards for affected EGUs in that subcategory. After reviewing public comments and other available information, the EPA concludes that such a subcategory is warranted. Thus, this final action establishes a subcategory of certain existing EBCR-fired EGUs for emissions of hydrochloric acid (HCl) and sulfur dioxide (SO2)—both of which serve as a surrogate for all acid gas HAP emitted from EGUs under MATS. Under CAA section 112(d)(1), the EPA has the discretion to ‘‘. . . distinguish among classes, types, and sizes of sources within a category or subcategory in establishing . . . standards.’’ Further, when separate subcategories are established, the minimum level of PO 00000 Frm 00029 Fmt 4700 Sfmt 4700 20839 control, referred to as the ‘‘maximum achievable control technology (MACT) floor,’’ is determined separately for each subcategory. The EPA has determined that emission limits reflecting a more stringent (i.e., ‘‘beyond-the-floor’’) level of control than the MACT floor level of control are appropriate for the new subcategory. The SO2 emission standard (set in pounds (lb) SO2/million British thermal units (MMBtu)) that the EPA is promulgating here is an emission rate that the currently operating EBCR-fired EGUs have demonstrated an ability to achieve based on their emissions data and considering cost and non-air quality related environmental factors.1 The EPA does not have corresponding emissions data for HCl 2 or output-based emissions of SO2 (i.e., lb SO2/megawatt-hour (MWh)) and, therefore, the EPA has established the final beyond-the-floor standards for SO2 (in lb/MWh) and for HCl (in both lb/MMBtu and lb/MWh) consistent with the percentage reduction in the SO2 lb/MMBtu emissions rate between the MACT floor value and the beyond-the-floor value. This action establishes the following emission limits for the subcategory of existing EBCR-fired EGUs: 3 HCl: 4.0E–2 lb/MMBtu or 4.0E–1 lb/MWh SO2: 4 6.0E–1 lb/MMBtu or 9.0 lb/MWh. A further description of what the EPA is promulgating here, the rationale for the final decisions, and discussion of the key comments received regarding the need for such a subcategory and the acid gas HAP emission standards appropriate for that subcategory are provided in section III of this preamble. B. Does this action apply to me? Categories and entities potentially regulated by this action are shown in Table 1 of this preamble. 1 For context, the 2012 final MATS emission standard for SO2 is 2.0E–1 lb/MMBtu. 2 For MATS, affected sources may report emissions of either SO2 or HCl. Most MATSaffected EGUs report emissions of SO2 because they already have the monitoring infrastructure to do so, since most already report SO2 emissions under the EPA’s Acid Rain Program. 3 Continuous compliance with the emission limits is required to be demonstrated on a 30-boiler operating day rolling average basis. 4 As is the requirement for all coal-fired EGUs subject to MATS, the alternate SO2 limit may be used if the EGU has some form of flue gas desulfurization (FGD) system and SO2 continuous emissions monitoring systems (CEMS) and both are installed and operated at all times. E:\FR\FM\15APR1.SGM 15APR1 20840 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations with reasonable specificity during the TABLE 1—NESHAP AND INDUSTRIAL SOURCE CATEGORIES AFFECTED BY period for public comment (including any public hearing) may be raised THIS FINAL ACTION during judicial review. This section also provides a mechanism for the EPA to NAICS reconsider the rule if the person raising an objection can demonstrate to the Coal- and Oil-Fired EGUs .... 221112, Administrator that it was impracticable 221122 to raise such objection within the period a North American Industry Classification for public comment or if the grounds for such objection arose after the period for System. public comment (but within the time Table 1 of this preamble is not specified for judicial review) and if such intended to be exhaustive, but rather to objection is of central relevance to the provide a guide for readers regarding outcome of the rule. Any person seeking entities likely to be affected by the final to make such a demonstration should action for the source category listed. submit a Petition for Reconsideration to Specifically, entities that own and/or the Office of the Administrator, U.S. operate certain existing EBCR-fired EPA, Room 3000, WJC South Building, EGUs subject to the NESHAP for Coal1200 Pennsylvania Ave. NW, and Oil-Fired EGUs (40 CFR part 63, Washington, DC 20460, with a copy to subpart UUUUU) will be affected by this both the person(s) listed in the final action. To determine whether your preceding FOR FURTHER INFORMATION facility is affected, you should examine CONTACT section of this preamble, and the applicability criteria in the NESHAP the Associate General Counsel for the for Coal- and Oil-Fired EGUs and the Air and Radiation Law Office, Office of amendatory text of this final action. If General Counsel (Mail Code 2344A), you have any questions regarding the U.S. EPA, 1200 Pennsylvania Ave. NW, applicability of any aspect of this Washington, DC 20460. NESHAP, please contact the appropriate II. Background person listed in the preceding FOR FURTHER INFORMATION CONTACT section of The NESHAP for Coal- and Oil-Fired this preamble. EGUs (commonly referred to as MATS) was proposed on May 3, 2011 (76 FR C. Where can I get a copy of this 24976), under title 40, part 63, subpart document and other related UUUUU. In that proposal, the EPA information? proposed a single acid gas HAP In addition to being available in the emission standard for all coal-fired docket, an electronic copy of this action power plants—using HCl as a surrogate is available on the internet. Following for all acid gas HAP. The EPA also signature by the EPA Administrator, the proposed an alternative equivalent EPA will post a copy of this final action emission standard for SO2 as a surrogate at https://www.epa.gov/mats/regulatory- for all the acid gas HAP for coal-fired actions-final-mercury-and-air-toxicsEGUs with FGD systems and SO2 CEMS standards-mats-power-plants. installed and operational at all times. Following publication in the Federal SO2 is also an acidic gas—though not a Register, the EPA will post the Federal HAP—and the controls used for SO2 Register version of the final rule and emission reduction are also effective at key technical documents at this same controlling the acid gas HAP emitted by website. EGUs. Further, most, if not all, affected EGUs already measure and report SO2 D. Judicial Review and Administrative emissions as a requirement of the EPA’s Reconsideration Acid Rain Program, 40 CFR part 75. Under CAA section 307(b)(1), judicial The Appalachian Region Independent review of this final action is available Power Producers Association only by filing a petition for review in (ARIPPA) 5 submitted comments on the the United States Court of Appeals for 2011 MATS proposal arguing that the the District of Columbia Circuit characteristics of all coal refuse made (hereafter referred to as ‘‘the D.C. achievement of the standard too costly Circuit,’’ or ‘‘the Court’’) by June 15, for its members and requested that the 2020. Under CAA section 307(b)(2), the EPA create a subcategory for all EGUs requirements established by this final burning coal refuse. The EPA rule may not be challenged separately in determined that there was no basis to any civil or criminal proceedings 5 ARIPPA is a non-profit trade association brought by the EPA to enforce the comprised of independent electric power requirements. producers, environmental remediators, and service Section 307(d)(7)(B) of the CAA providers located in Pennsylvania and West further provides that only an objection Virginia that use coal refuse as a primary fuel to to a rule or procedure which was raised generate electricity. jbell on DSKJLSW7X2PROD with RULES NESHAP and source category VerDate Sep<11>2014 16:09 Apr 14, 2020 code a Jkt 250001 PO 00000 Frm 00030 Fmt 4700 Sfmt 4700 create such a subcategory and, on February 16, 2012 (77 FR 9304), finalized emission standards for both HCl and SO2 that apply to all coal-fired EGUs, including the coal refuse-fired units subject to this final action. ARIPPA, along with other petitioners, challenged the EPA’s determination in the D.C. Circuit, and the Court upheld the final rule. White Stallion Energy Center, et. al. v. EPA, 748 F.3d 1222, 1249–50 (D.C. Cir. 2014). In addition to challenging the final rule, ARIPPA also petitioned the EPA for reconsideration, again requesting a subcategory for the acid gas standards for facilities combusting all types of coal refuse. The EPA denied the Petition for Reconsideration on grounds that ARIPPA had adequate opportunity to comment on the ability of coal refusefired facilities to comply with the final standard. Furthermore, the EPA determined that the ARIPPA petition did not present any new information to support a change in the previous determination regarding the appropriateness of a subcategory for the acid gas HAP standard. ARIPPA subsequently sought judicial review of the denial of the Petition for Reconsideration. ARIPPA v. EPA, No. 15–1180 (D.C. Cir.).6 In petitioner’s briefs, ARIPPA claimed that the EPA had misunderstood its reconsideration petition and pointed to a distinction between the control of acid gas HAP emissions from units burning anthracite coal refuse and those burning bituminous coal refuse. See Industry Pets. Br. at 35–36, ARIPPA, No. 15–1180 (D.C. Cir. filed December 6, 2016). The EPA disagrees with the assertion that the Agency misunderstood the basis for ARIPPA’s reconsideration petition as we could not find a single statement in the rulemaking record that clearly or even vaguely requested a separate acid gas HAP limit based on the distinction between anthracite coal refuse and bituminous coal refuse. Nonetheless, the EPA has since looked at emissions data from these sources and observed that there are differences in emissions based on the type of coal refuse used, and, consequently, recognized the differences in the 2019 Proposal.7 Specifically, the EPA recognized that there are differences between anthracite coal refuse and bituminous coal refuse, and that the type of fuel used leads to differences in the acid gas HAP 6 ARIPPA’s petition for review is currently being held in abeyance. ARIPPA v. EPA, No. 15–1180, Order, No. 1672985 (April 27, 2017). 7 The analysis is summarized in a separate memorandum titled HCl and SO2 Emissions for Coal Refuse-Fired EGUs, available in Docket ID No. EPA–HQ–OAR–2018–0794. E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations emissions from EGUs firing those respective fuels. The Agency also noted that the differences may impact the unit’s ability to control those emissions. Additionally, the EPA recognized that there are differences between western bituminous coal refuse and subbituminous coal refuse as compared to EBCR and announced in the 2019 Proposal that it was considering establishing a subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP. The proposal solicited comment on whether establishment of such a subcategory is needed and on the acid gas HAP emission standards that would be established if such a subcategory was created. 84 FR 2700– 2703. III. Summary of Final Action After considering and evaluating comments and data provided in response to the solicitation of comment on establishing a subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP in its 2019 Proposal, the EPA is taking final action to establish a separate subcategory to address the issue. In this final action, the EPA is establishing a subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP and acid gas HAP emission standards that are applicable to the new subcategory. The final rule defines Eastern bituminous coal refuse (EBCR) to mean coal refuse generated from the mining of bituminous coal in Pennsylvania and West Virginia. The final rule defines Unit designed for eastern bituminous coal refuse (EBCR) subcategory to mean any existing (i.e., construction was commenced on or before May 3, 2011) coal-fired EGU with a net summer capacity of no greater than 150 megawatts (MW) that is designed to burn and that is burning 75 percent or more (by heat input) eastern bituminous coal refuse on a 12-month rolling average basis. The 150 MW net summer capacity level selected by the EPA limits the universe of sources that are in the new subcategory to only those EGUs identified in Table 2 to this preamble. Net summer capacity is the maximum output that generating equipment can supply to system load at the time of summer peak demand (period of June 1 through September 30). The 75 percent or more heat input requirement selected by the EPA is consistent with the Federal Energy Regulatory Commission 20841 requirement that to be considered a qualifying facility under the Public Utility Regulatory Policies Act, as the EGUs in the new subcategory are, at least 75 percent of the heat content must come from coal refuse. The existing EBCR-fired EGUs in the new subcategory being established in this action are listed in Table 2 of this preamble and the applicable HCl and SO2 limits being finalized in this action are provided in Table 3 of this preamble. Four existing EBCR-fired EGUs at two facilities that were listed in the 2019 Proposal as being part of the new subcategory, if established, are no longer part of the subcategory. The EPA has learned that the Cambria facility shut down in June 2019, and the facility and surrounding property have been sold to a salvage company which plans to dismantle the facility over time.8 The EPA has also learned that the Morgantown Energy facility will be transformed into a natural gas-fueled steam-only production facility, and the closure of the waste coal-fired boilers and complete transformation of the facility to steam-only production are expected to be completed by early to mid-2020.9 TABLE 2—EBCR-FIRED EGUS IN SUBCATEGORY ORIS plant code a 10143 10151 10151 10603 50974 50974 EGU .......................................... .......................................... .......................................... .......................................... .......................................... .......................................... State Colver Power Project ...................................................................... Grant Town Power Plant Unit 1A .................................................... Grant Town Power Plant Unit 1B .................................................... Ebensburg Power ............................................................................ Scrubgrass Generating Company LP Unit 1 .................................. Scrubgrass Generating Company LP Unit 2 .................................. Summer capacity (MW) PA WV WV PA PA PA 110 40 40 50 42 42 2016 average monthly generation (MWh) b 60,905 28,010 28,010 16,258 17,377 17,377 a Unique plant identification code assigned by the Department of Energy’s Energy Information Administration (EIA). annual generation is based on plant-level data reported on EIA Form 923, and annual totals are divided evenly to estimate 2016 average monthly generation. Unit-level estimates assume that generation is split evenly between all units at each plant. b 2016 TABLE 3—ACID GAS EMISSION LIMITATIONS FOR EBCR–FIRED EGUS SUBCATEGORY Emission limit a Subcategory SO2 b HCl Existing Eastern Bituminous Coal Refuse-Fired EGUs .......... 4.0E–2 lb/MMBtu ................................... or 4.0E–1 lb/MWh ...................................... 6.0E–1 lb/MMBtu or 9.0 lb/MWh jbell on DSKJLSW7X2PROD with RULES a Units of emission limits: lb/MMBtu = pounds pollutant per million British thermal units fuel input; and lb/MWh = pounds pollutant per megawatt-hour electric output (gross). b Alternate SO limit may be used if the EGU has some form of FGD system and SO CEMS installed. 2 2 Sources in the new subcategory must comply with the applicable HCl or SO2 requirements no later than the effective date of this final rule. Sources must demonstrate that compliance has been achieved, by conducting the required performance tests and other activities as specified in 40 CFR part 60, subpart UUUUU, no later than 180 days after the compliance date. To demonstrate initial compliance using either an HCl or SO2 CEMS, the initial performance test 8 See https://www.tribdem.com/news/cambriacogen-plant-to-be-leveled-after-shutting-down-over/ article_005a162c-2381-11ea-8c535b85339774fd.html. 9 See https://www.nsenergybusiness.com/news/ starwood-energy-terminates-eepa/. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 PO 00000 Frm 00031 Fmt 4700 Sfmt 4700 E:\FR\FM\15APR1.SGM 15APR1 20842 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations jbell on DSKJLSW7X2PROD with RULES consists of 30-boiler operating days. If the CEMS is certified prior to the compliance date, the test begins with the first operating day on or after that date. If the CEMS is not certified prior to the compliance date, the test begins with the first operating day after certification testing is successfully completed. Continuous compliance with the newly established emission limits is required to be demonstrated on a 30-boiler operating day rolling average basis. The EPA’s final decisions regarding establishing a subcategory for certain existing EGUs that fire EBCR and the acid gas HAP standards applicable to the new subcategory are provided later in this section of this preamble. Specifically, the EPA’s rationale for the final decisions and discussion relating to the key comments received regarding the need for such a subcategory and the attendant acid gas HAP emission standards are provided. A summary of all significant public comments regarding the EPA’s consideration of establishing such a subcategory and the EPA’s responses to those comments is available in the document titled Summary of Public Comments and Responses Regarding Establishment of a Subcategory and Acid Gas HAP Emission Standards for Certain Existing Eastern Bituminous Coal Refuse-Fired EGUs (response to comments document), Docket ID No. EPA–HQ– OAR–2018–0794. A ‘‘track changes’’ version of the regulatory language that incorporates the changes in this action is also available in the docket for this action. A. Basis for Subcategory Under CAA section 112(d)(1), the Administrator has discretion to ‘‘* * * distinguish among classes, types, and sizes of sources within a category or subcategory in establishing * * *’’ standards. Based on the EPA’s better understanding of the differences in anthracite coal refuse and bituminous coal refuse, and the acid gas HAP emissions profile associated with each, the EPA has now determined that, contrary to its earlier position, it is appropriate to establish a new subcategory for certain units firing EBCR. Specifically, the EPA is establishing a new subcategory for certain units with a net summer capacity of 150 MW or lower that fire EBCR because there are differences between emissions of acid gas HAP from these units and larger units burning EBCR and units burning other types of coal, including other types of coal refuse. See U.S. Sugar Corp. v. EPA, 830 F.3d 579, 656 (DC Cir. 2016) (finding VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 that ‘‘[s]ection 7412(d) gives the EPA discretion to create subcategories based on boiler type, and nothing in the statute forecloses the Agency from doing so based on the type of fuel a boiler was designed to burn.’’). Units in this new subcategory of EGUs are smaller, were designed to burn EBCR, and were constructed in close proximity to legacy piles of EBCR for the primary purposes of reclaiming abandoned mining sites while reducing the environmental hazards attendant to such piles of coal refuse. The EPA cannot predict with certainty what the industry response would be absent the establishment of a new subcategory as discussed in greater detail elsewhere in this preamble and in a docketed memorandum on expected costs and benefits. Among those possible outcomes, many industry commenters and others have suggested that some—and maybe all—of the affected sources would shut down.10 If that is the case, then the establishment of this new subcategory will allow those units to continue to achieve both of their purposes of reclaiming abandoned mining sites and preserving the environmental benefits of repurposing coal refuse, while also maintaining emissions of acid gas HAP at levels similar to current emissions levels.11 Immediately below and in the response to comments document, we discuss in more detail the basis for the new subcategory and address the significant comments on the new subcategory. As stated in the 2019 Proposal, the EPA finds that the emissions of acid gas HAP from EGUs firing EBCR are distinct from acid gas HAP emissions from EGUs firing other types of coal—including other forms of coal refuse. Specifically, the EPA recognized in the 2019 Proposal that there are differences between anthracite coal refuse and bituminous coal refuse, and that the type of fuel used leads to differences in the acid gas HAP emissions from EGUs 10 While the EPA cannot predict with certainty what the industry response would be in the absence of a new subcategory, commenters’ claims that the units would shut down is plausible. Coal-fired power plants are currently facing tremendous competitive pressures. As a result, coal’s share of total U.S. electricity generation has been declining for over a decade, while generation from natural gas and renewables has increased significantly. A large number of coal units—especially smaller ones like the EBCR-fired EGUs—have retired since 2010. As mentioned earlier, four of the ten units that were identified as affected by this action in the 2019 Proposal have now either retired or announced plans to convert to natural gas. 11 EBCR-fired EGUs were designed to achieve a control level generally at or exceeding 90 percent SO2 reduction (see EPA Docket ID Item Nos. EPA– HQ–OAR–2018–0794–1125, EPA–HQ–OAR–2018– 0794–1154, and EPA–HQ–OAR–2018–0794–1187). PO 00000 Frm 00032 Fmt 4700 Sfmt 4700 firing those respective fuels. Bituminous coals (and, thus, bituminous coal refuse) from the Appalachian and Interior Regions of the U.S. have higher sulfur and chlorine contents than anthracite or coals of all types from the Western Region of the U.S. (and, thus, anthracite coal refuse or western bituminous and subbituminous coal refuse), and these differences lead to differences in emissions of acid gas HAP. These differences between the types of coal refuse used by EGUs to generate electricity may also impact a unit’s ability to control those emissions. All coal refuse fuels are fired in fluidized bed combustors (FBC) that use limestone injection to reduce SO2 emissions and to increase heat transfer efficiency. The EPA has been informed that limestone injection technology is generally adequate to allow EGUs that are firing anthracite coal refuse and western coal refuse to meet the 2012 final MATS alternative surrogate emission standard of 2.0E–1 lb/MMBtu for SO2.12 This is because anthracite coals are naturally much lower in impurities (including sulfur and chlorine) and western coals (western bituminous coal and subbituminous coal) have lower sulfur and chlorine content and higher free alkalinity (which can act as a natural sorbent to neutralize acid gases produced in the combustion process). The same is not generally true for EGUs combusting EBCR. Because all existing EGUs firing anthracite coal refuse and western bituminous coal refuse are currently emitting SO2 at rates that are below the 2012 final MATS emission standard for SO2 and the existing EGU firing subbituminous coal refuse is currently emitting HCl at a rate that is below the 2012 final MATS emission standard for HCl, the EPA believes there is no need to broaden the subcategory to include those units. The EBCR-fired EGUs that will be included in the new subcategory are also small units (all have capacities less than 120 MW and most are less than 100 MW). As contemplated in the 2019 Proposal, this final rule excludes the two EBCR-fired EGUs at the Seward Generating Station in Pennsylvania from the new subcategory. 84 FR 2702. Those units are the newest and, at 260 MW each, are, by far, the largest coal refusefired EGUs. The Seward units were also designed and constructed with downstream acid gas controls already incorporated, so they do not have the space limitations and other configurational challenges that may 12 See Table 2 to subpart UUUUU of 40 CFR part 63. E:\FR\FM\15APR1.SGM 15APR1 jbell on DSKJLSW7X2PROD with RULES Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations affect other smaller existing EBCR-fired EGUs attempting to retrofit air pollution controls. Retrofitting air pollution controls to an existing EGU can often be challenging due to lack of available space within the facility and the potential need to re-route the exhaust gas stream to accommodate such equipment configurational changes. Control equipment that results in pressure drop along the exhaust stream can challenge existing blowers. These challenges and space limitations can be considered in the design of a new facility. The Seward units were among the best performing EGUs—with respect to HCl emissions—when the EPA developed the final MATS emission standards and, based on MATS compliance reports for the Seward EGUs, currently emit HCl at well below the final MATS HCl standard of 2.0E– 3 lb/MMBtu, applicable to coal-fired EGUs.13 In response to the 2019 Proposal’s solicitation of comment, the EPA received comments both supporting and opposing the establishment of a subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP. Several commenters pointed out the environmental benefits provided by EBCR-fired EGUs in the coal regions where they are located. Specifically, commenters pointed out that removal of coal refuse piles reduces surface and groundwater pollution from acidic drainage and reduces uncontrolled emissions of air pollutants that are released from self-ignited internal smoldering of the coal refuse piles. In addition, commenters pointed out that the alkaline ash produced by EBCR-fired EGUs is used to reclaim mining-affected lands by returning them to a productive use. Commenters further noted that the Pennsylvania Department of Environmental Protection has standards governing such beneficial use of coal ash in mine land reclamation (Title 25 PA Code, Chapter 290).14 Several commenters asserted that the 2012 final MATS limits for acid gas HAP and their SO2 surrogate are not achievable by EBCR-fired EGUs and do not reflect the design, functionality, and economics of those units. Commenters stated that while limestone injection into the unit’s combustion zone controls SO2 and HCl emissions to a certain extent, there are operational and design limitations on the EGUs’ ability to provide an adequate amount of 13 Ibid. 14 See https://www.dep.pa.gov/Business/Land/ Mining/BureauofMiningPrograms/Pages/CoalAsh BeneficialUse.aspx. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 limestone to reduce SO2 and HCl emissions beyond a certain point. Commenters further stated that the reduction of SO2 and acid gases through increased injection of limestone is asymptotic, and significant additional limestone does not result in further significant acid gas emission reduction. Commenters explained that the configuration of the EGUs and their combustion zone physically limit the amount of material that the unit can hold, which impacts and limits the amount of coal refuse and limestone that can be injected into the unit. Commenters explained, for example, that increasing the amount of limestone injected to achieve the 2012 final MATS SO2 emission limit could result in less coal refuse being fired. This would result in a corresponding reduction in steam production and electricity generation, making it uneconomic to operate in the current power market. The EPA does not have detailed information regarding the specific amount of limestone that is injected into the EBCR-fired EGUs. However, the Agency acknowledges that it is current industry practice to inject limestone into the FBC in amounts based on an optimized calcium-to-sulfur (Ca:S) molar ratio. Therefore, the optimum limestone injection amount will vary with the sulfur content of the coal refuse being burned. Along with the coal (fuel) and limestone that are injected and utilized, the fluidized bed units also contain an inert bed material (e.g., sand or other). There is a limit to the amount of solid material—i.e., the sand, the coal refuse, coal ash, and limestone—that can be in the combustor. An increase in limestone injection may necessarily result in a decrease in coal refuse utilization. Utilization of the limestone for acid gas neutralization is dependent upon decomposition (calcination) of the limestone to lime and subsequent reaction of the lime with the acid gases via the following reactions: CaCO3 + heat → CaO + CO2 SO2 + CaO → CaSO3 2HCl + CaO → CaCl2 + H2O The necessary calcination of the limestone and the desulfurization reactions occur within specific temperature ranges (typically around ∼ 900 °Celsius or 1,650 °F) and the FBC operators must utilize sufficient fuel to maintain the boiler in the optimum temperature range. Lower temperatures result in insufficient calcination and lower boiler efficiency. Higher temperatures can result in materials sintering, which results in lower desulfurization capacity. PO 00000 Frm 00033 Fmt 4700 Sfmt 4700 20843 Commenters also noted concerns that a significant increase in limestone injection for control of SO2 emissions could negatively impact the ability to beneficially use the combustion fly ash.15 For example, for certain uses, the Pennsylvania Department of Environmental Protection Guidelines for Beneficial Use of Coal Ash at Coal Mines 16 warns that mixing of coal ash with conventional alkaline materials (e.g., limestone, lime, hydrated lime) may increase the likelihood of the coal ash becoming cementitious and reduce the neutralizing ability of the coal ash and the conventional material. In such cases, the captured fly ash would have to be disposed of in a lined landfill rather than beneficially reused. Commenters also contended that EBCRfired EGUs may have to consider switching from EBCR as the primary fuel to firing less EBCR along with a lower sulfur fuel as a means of reducing SO2 emissions to meet the 2012 final MATS SO2 emission limit. Commenters stated that such practice, in addition to being uneconomical, could reduce EBCR usage to below the minimum 75percent coal refuse heat input requirement to be considered a qualifying facility under the Public Utility Regulatory Policies Act. Commenters claimed that both approaches described earlier (i.e., increased limestone injection and fuel switching) undermine the environmental benefits realized by the EBCR-fired EGUs through clean-up of waste coal refuse sites. One commenter stated that regardless of limestone addition and fuel switching, meeting the 2012 final MATS SO2 limit would require additional control technology and likely result in permanent retirement of the facility. Several commenters pointed out that they are not aware of any retrofit installation of back-end scrubbing technology or a back-end dry sorbent injection (DSI) system for an EBCR-fired EGU. Commenters asserted that downstream acid gas controls cannot be considered technically or economically feasible for EBCR-fired EGUs and provided information regarding evaluation of such technologies. 15 The combustion ash is beneficially used on mine sites to fill pits, create or amend soil, and as a low-permeability or high alkalinity material. In Pennsylvania the regulations governing the beneficial use of coal ash are available at 25 PA Code Chapter 290. See https://www.dep.pa.gov/ Business/Land/Mining/BureauofMiningPrograms/ Pages/CoalAshBeneficialUse.aspx. 16 Pennsylvania Department of Environmental Protection Bureau of Mining Programs; Document Number: 563–2112–228; Guidelines for Beneficial Use of Coal Ash at Coal Mines; Effective date: December 17, 2016. E:\FR\FM\15APR1.SGM 15APR1 20844 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations jbell on DSKJLSW7X2PROD with RULES Commenters claimed that adding on back-end control equipment would boost sulfur capture, but the capital and operating costs increases would not be supported by power sales revenues. Commenters further claimed that in addition to being cost prohibitive for the small EBCR units, control strategies such as wet FGD scrubbers and spray dryer absorbers (SDA) present installation difficulties given layout of the facilities, local topography, and needs of the systems to interface with existing EGU equipment.17 Although commenters acknowledged that DSI systems do not present such technical challenges with deployment, they pointed out other problems associated with the alkaline sorbents (typically sodium- or calcium-based) injected in such systems. Several commenters stated that coal refuse-fired EGUs currently achieve extremely efficient mercury (Hg) control due, at least in part, to the relatively high levels of chlorine in coal refuse which can promote the oxidation of the Hg to the divalent form. This, coupled with the higher levels of unburned carbon in the fly ash, allows the Hg to be more readily captured in the downstream baghouse (i.e., fabric filter particulate matter (PM) control device) and not emitted through the stack. Commenters explained that reducing the amount of chlorine (or HCl) in the flue gas prior to the oxidation reaction can have the effect of increasing Hg emissions from the facility. One commenter stated that their testing of both sodium- and calciumbased sorbents injected at the inlet of the baghouse (essentially in a DSI configuration) resulted in an increase in Hg emissions by a factor of 4 to 40 times resulting in levels exceeding the 2012 final MATS Hg emission limit.18 Therefore, the commenter asserted that, even if technically feasible, the use of DSI could affect the unit’s ability to meet other MATS emission limits. Several commenters stated that the potential for DSI technology to have a negative impact on the ability to use combustion ash for mine site reclamation and restoration activities would remove it as a viable alternative. Commenters explained that use of sodium-based sorbents (e.g., trona or sodium bicarbonate) could alter the 17 See EPA Docket ID Item Nos. EPA–HQ–OAR– 2018–0794–1154 and EPA–HQ–OAR–2018–0794– 1160 for additional discussion of commenters’ claims of physical and configurational difficulties in installing downstream control technologies. 18 This testing is described in materials provided to the EPA by ARIPPA during a March 13, 2013, meeting. The materials are available in the previous MATS rulemaking Docket ID Item No. EPA–HQ– OAR–2009–0234–20338 and in the current Docket ID No. EPA–HQ–OAR–2018–0794. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 leaching characteristics of the ash such that it would no longer be of beneficial use and would have to be disposed of in a lined landfill. One commenter stated that testing at their facility confirmed such a change in the quality of the ash to the point that it was at risk of failing to satisfy leaching requirements of the standards for beneficial use in mine land reclamation. Commenters claimed that ash disposal costs, especially when considering the significant quantity of ash generated, would far exceed the revenue generated through the sale of electricity. Commenters also pointed out that significant environmental benefits provided by EBCR-fired EGUs would be eliminated if the ash cannot be beneficially used. Several commenters asserted that there is no justification for establishing a subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP. Commenters claimed that the EPA has not provided a valid technical basis for the subcategory, stating that while the EPA has said that eastern bituminous coal is distinguished by higher sulfur content and lesser content of free alkali, the EPA offers nothing to distinguish the EGUs it would subcategorize from other EGUs burning the same coals and subject to MATS. Commenters further claimed that there is no basis for a subcategory for EBCRfired EGUs because some of those EGUs currently emit SO2 at rates below the 2012 final MATS SO2 limit and have shown that the current standards are achievable because there are technologies that are feasible. Commenters stated that the assessment of the need for a subcategory cannot reasonably be based on data for the period of January 2015 through June 2018, terminating before EGUs reported results of installed pollution controls. Commenters added that even if limestone injection alone is not adequate to meet the MATS limits, the fact that certain EGUs would need to install additional controls is not a valid basis for a subcategory. Commenters also added that the EPA may not subcategorize based on cost, even if some add-on controls would be particularly expensive, and the EPA may not alter the MACT floor because some sources may not be able to meet it. Commenters further stated that the EPA notes that the use of some sorbents may negatively impact the salability of fly ash, but commenters contend that losing the ability to sell the ash—a consequence for all EGUs using DSI, not just those using eastern bituminous coal-waste—does not suggest any basis PO 00000 Frm 00034 Fmt 4700 Sfmt 4700 in the class, type, or size of the EGUs at the six plants that might allow the EPA to set different standards for those EGUs. Commenters pointed to a plant within the proposed subcategory that they contend demonstrates that units can meet the MATS acid gas limits while still re-using their ash. Commenters refuted the EPA’s assertion that use of DSI technology results in a considerable increase in Hg emissions and would require the use of additional Hg controls, and, further, stated that even if true, it provides no lawful basis for the subcategory. Commenters pointed to EBCR-fired EGUs that they contend not only can meet both the MATS acid gas and Hg limits, they can achieve such low emissions of Hg that they qualify for low-emitting EGU status (i.e., their emissions are less than 10 percent of the MATS limit) without any Hg-specific controls. Commenters added that CAA section 112 does not permit the EPA to loosen emission limitations based on the EPA’s desired control configuration. The EPA disagrees with comments opposed to establishing a new subcategory of certain existing EGUs firing EBCR for emissions of acid gas HAP. Under CAA section 112(d)(1), the Administrator has the discretion to ‘‘ * * * distinguish among classes, types, and sizes of sources within a category or subcategory in establishing * * * ’’ standards. The EPA generally establishes subcategories to address differences between units that make the nature of the HAP emissions different or if there are technical feasibility issues associated with different emission control approaches. Normally, the basis for subcategorizing (e.g., type of unit) must be related to an effect on emissions, rather than some difference which does not affect emissions performance. EGUs are generally designed for a particular type of fuel, and the type of fuel being burned can impact the degree of combustion and the level and type of HAP emissions because the amount of fuel-borne HAP such as acid gases is primarily dependent upon the composition of the fuel. In addition, the type of fuel and attendant unit design can limit the availability and functionality of different types of controls, particularly for existing sources that must retrofit if add-on controls are required. Finally, the D.C. Circuit recently confirmed that the EPA may establish a subcategory based on the type of fuel a boiler is designed to burn. See U.S. Sugar Corp. v. EPA, 830 F.3d at 656. Consistent with the statute and case law, the EPA is establishing a subcategory based on the E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations size (boiler 150 MW or less) and type (boiler designed to burn EBCR) to address the different acid gas HAP emissions from such sources. To inform our consideration, the EPA reviewed EGU design, operating information, air emissions data compiled from the 2010 Information Collection Request (ICR) that was used by the EPA during development of the 2012 MATS final rule, and other available information for coal-fired EGUs in the source category. The EPA found that there are significant design and operational differences in coal-fired EGUs that are based on the expected source of fuel and the design of the unit that affect the levels of emissions of HCl and SO2—both of which serve as a surrogate for all acid gas HAP emitted from coal-fired EGUs under MATS. These differences support our decision to establish a subcategory for existing EGUs that burn EBCR and have a net summer capacity of 150 MW or lower. Specifically, the emissions data for HCl and SO2 show a distinguishable difference in performance exists between coal-fired units with a net summer capacity of no greater than 150 MW designed to burn EBCR and other coal-fired units, including units that burn coal refuse other than EBCR.19 20 Because the EBCR-fired units have different emission characteristics for acid gas HAP, the EPA has determined that units that are designed to burn EBCR, and actually burn at least 75percent EBCR, are a different type of unit and should be subcategorized for acid gas HAP emissions.21 The determination that EBCR-fired EGUs have different emission characteristics for acid gas HAP is reasonably based on the same 2010 ICR dataset used to establish the bases of subcategories and standards in the 2012 MATS final rule. An examination of the data shows that there were no coal-fired units with a net summer capacity of 150 MW or less designed to burn EBCR among the top performing 12 percent of coal-fired units for emissions of HCl or SO2, even though the EPA used 12 percent of the entire source category (130 units) to establish the acid gas HAP jbell on DSKJLSW7X2PROD with RULES 19 As discussed earlier in this section of this preamble, the subcategory being established in this final rule excludes the two EBCR-fired EGUs at the Seward Generating Station, which are 260 MW each, from the new subcategory. 20 See the memorandum titled HCl and SO 2 Emissions for Coal Refuse-Fired EGUs, available in Docket ID No. EPA–HQ–OAR–2018–0794. 21 For all other HAP from these two subcategories of coal-fired units, the data did not show any difference in the level of the HAP emissions and, therefore, we have determined that it is not reasonable to establish separate emissions limits for the other HAP. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 standard for coal-fired EGUs. There were, however, EGUs firing bituminous coal, subbituminous coal, and lignite among the top performing units for HCl and EGUs firing bituminous, subbituminous, lignite, and non-EBCR coal refuse among the top performers for SO2. The EPA points out that the assessment of the need for a subcategory was not based on data for the period of January 2015 through June 2018 as suggested by commenters. As discussed in section III.B of this preamble, those data were used to determine the SO2 lb/ MMBtu emission rate for beyond-thefloor level of control. The EPA disagrees with commenters’ assertions that the fact that some EBCR-fired EGUs have met the 2012 final MATS SO2 limit means the new subcategory is unreasonable. The EPA is aware of EGUs at two plants 22 that have been able to meet the 2012 final MATS SO2 limit. Historical SO2 emissions data reported to the EPA’s Emissions Collection and Monitoring Plan System (ECMPS) for those EGUs shows that those plants had lower SO2 emissions than other EBCR-fired EGUs. Thus, the additional SO2 emissions reductions required for those EGUs to meet the 2012 final MATS SO2 limit are more likely to be achievable through means such as increased limestone injection and fuel switching without the limitations described by several commenters and summarized earlier in this section of the preamble. The EPA’s understanding, however, is that the operational changes made to those EGUs with historically lower SO2 emissions in order to meet the 2012 final MATS SO2 limit result in less EBCR being disposed of and are not economically feasible in the long term. One facility has met the SO2 limit by injecting more limestone and the other facility has met the limit by co-firing lower sulfur coal. Similarly, the ability of those same units to meet the 2012 final MATS acid gas HAP limit as well as the Hg limit or to meet the 2012 final MATS acid gas HAP limit while still re-using their ash does not mean a separate subcategory is unwarranted or unreasonable. The information in the record supports a conclusion that the existing EGUs in the new subcategory are different from a fuel and design perspective and it is reasonable to establish a new subcategory based on the size and type of unit. In addition, this new subcategory is also reasonable because the alternative is to maintain a standard 22 Neither of these two plants with EBCR-fired EGUs that have met the 2012 final MATS SO2 limit are the Seward Generating Station discussed earlier in this section of this preamble. PO 00000 Frm 00035 Fmt 4700 Sfmt 4700 20845 that requires the sources to operate in a manner that undermines the purpose for which they were constructed and may be technologically infeasible for certain units in the subcategory. Specifically, the coal refuse-fired EGUs at issue were constructed at or near legacy piles of EBCR for the primary purposes of reducing the health and environmental hazards associated with the coal piles and using the resultant coal ash to reclaim abandoned mining sites. The commenters in support of the rule provided information indicating the reasons the new subcategory is warranted and how requiring compliance with the 2012 MATS limit for acid gas HAP would undermine the continued viability of the EBCR-fired EGUs to perform both of these functions. For all these reasons, we do not agree that the commenters have raised any significant objections to the EPA’s determination that it is reasonable and appropriate to establish a new subcategory for EBCR-fired EGUs. Accordingly, we are finalizing the new subcategory. B. Subcategory Emission Standards As noted in the 2019 Proposal, the EPA conducted an analysis to determine the numerical acid gas emission standards for the subcategory of certain existing EGUs that fire EBCR should such a subcategory be established.23 The EPA explained that it determined the MACT floor and the beyond-the-floor (i.e., more stringent than the MACT floor) levels of control for HCl and SO2 emissions. The EPA further explained that the SO2 lb/MMBtu emission rate for beyond-the-floor level of control was determined for each currently operating EBCR-fired EGU using monthly SO2 data available in the EPA’s ECMPS for the period of January 2015 through June 2018.24 The EPA stated that if a beyondthe-floor (with floor at 1.0 lb/MMBtu) SO2 emissions limit was established, it would likely be in the range of 0.60– 0.70 lb/MMBtu; a limit that, on average, the currently operating EBCR-fired EGUs have demonstrated an ability to 23 The analysis is summarized in a separate memorandum titled NESHAP for Coal- and OilFired EGUs: MACT Floor Analysis and Beyond the MACT Floor Analysis for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs Under Consideration, available in Docket ID No. EPA–HQ– OAR–2018–0794. 24 At the time of the 2019 Proposal’s analysis, SO 2 data through June 2018 were available. Data that have become available only after the 2019 Proposal is not a necessary basis of our discussion of that Proposal or the EPA’s final action here, but it generally corroborates the basis already available and noticed to the public in February 2019. New data that have since become available to the EPA are discussed later in this section of this preamble. E:\FR\FM\15APR1.SGM 15APR1 20846 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations achieve based on their monthly emissions data for January 2015 through June 2018. The EPA explained that due to data limitations (i.e., no HCl lb/ MMBtu or lb/MWh emissions data have been submitted for the currently operating EBCR-fired EGUs, and SO2 lb/ MWh emissions data are available for only two of the currently operating EBCR-fired EGUs), this same beyondthe-floor methodology used to determine the beyond-the-floor standards for SO2 in lb/MMBtu could not be used to evaluate beyond-the-floor standards for SO2 in lb/MWh or for HCl in either lb/MMBtu or lb/MWh. The EPA, therefore, further explained that it determined that beyond-the-floor standards for those pollutants, if established, should reasonably be set based on the same percentage reduction as the SO2 lb/MMBtu described earlier (i.e., the 40-percent reduction in the emissions rate for SO2 between the calculated MACT floor value of 1.0 lb/ MMBtu and the beyond-the-floor value of 0.60 lb/MMBtu). The EPA solicited comment on the analysis conducted to determine the numerical acid gas emission standards and, on its methodology, and results. Table 4 of this preamble shows the results of the MACT floor and beyond-the-floor analyses as discussed in the 2019 Proposal. TABLE 4—MACT FLOOR AND BEYOND-THE-FLOOR RESULTS FOR POTENTIAL EBCR-FIRED EGUS SUBCATEGORY Subcategory Parameter HCl Existing Eastern Bituminous Coal Refuse-Fired EGUs ....... Number in MACT Floor ........................ 99% UPL a of Top 5 (i.e., MACT floor) 5 ............................. 6.0E–2 lb/MMBtu ... 6.0E–1 lb/MWh ...... 4.0E–2 lb/MMBtu ... 4.0E–1 lb/MWh ...... Beyond-the-floor Standard ................... jbell on DSKJLSW7X2PROD with RULES a Upper SO2 5 1.0 lb/MMBtu 15 lb/MWh 6.0E–1 lb/MMBtu 9.0 lb/MWh prediction limit. Immediately below and in the response to comments document, we discuss in more detail the basis for the acid gas HAP emission standards that are applicable to the new subcategory and address the significant comments on the standards for the new subcategory. In response to the 2019 Proposal’s solicitation of comment, the EPA received comments both supporting and opposing its analysis to determine the numerical acid gas emission standards for a subcategory of existing EBCR-fired EGUs. Several commenters agreed with the methodology that the EPA used to determine the MACT floor and beyondthe-floor levels of control for emissions of SO2 and HCl. Commenters further stated that an SO2 limit of 0.6 lb/ MMBtu, as discussed in the 2019 Proposal, is reasonable, technologically and economically defensible, and would allow facilities to continue providing multimedia environmental benefits from coal refuse reclamation and remediation of mining-affected lands. Other commenters disagreed with the EPA’s analyses of the MACT floor and beyondthe-floor levels of control and the resulting emission limits presented in the 2019 Proposal. Specifically, commenters disagreed with the data used in the analyses, claiming that it is not representative of the emissions reductions achieved in practice by the best-performing sources because it excludes time periods when controls were installed. In addition, commenters stated that the beyond-the-floor analysis fails to recognize that each plant in the subcategory already has acid gas controls sufficient to meet the current standard and, instead, assumes that VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 such controls are infeasible. Further, commenters stated that the only relevant cost for purposes of any beyond-the-floor standard is the cost of operating (rather than installing) the control. The EPA disagrees with those comments opposing the data used in the MACT floor and beyond-the-floor analyses and the resulting emission limits. The MACT floor analyses for HCl and SO2 for the subcategory of EBCRfired EGUs are reasonably based on the same 2010 ICR dataset and methodology used to determine MACT floor emission values for pollutants regulated under the 2012 MATS final rule. HCl and SO2 emissions data for the EBCR-fired EGUs that were operating at the time of the 2012 MATS final rule were used to calculate separate existing source MACT floors for HCl in lb/MMBtu and lb/MWh and SO2 in lb/MMBtu and lb/MWh. Thus, the MACT floor analysis and resulting floor values are consistent with how MACT floors for other HAP emissions standards were calculated and are representative of the HCl and SO2 emissions reductions achieved in practice by the best-performing EBCRfired EGUs at that time, irrespective of the means that the reductions were achieved. The beyond-the-floor analysis and resulting beyond-the-floor emission limit for SO2 lb/MMBtu are reasonably based on the extensive data available in the EPA’s ECMPS for each currently operating EBCR-fired EGU. As described in the 2019 Proposal, an SO2 emission limit of 0.6 lb/MMBtu is a limit that the currently operating EBCR-fired EGUs have demonstrated an ability to achieve based on their monthly emissions data PO 00000 Frm 00036 Fmt 4700 Sfmt 4700 for January 2015 through June 2018. Any means being used to control acid gases during that time period would be reflected in the average SO2 lb/MMBtu emission rate for those EBCR-fired EGUs. Thus, the EPA’s analysis does not exclude time periods when controls were installed. We note, however, that we are unaware of any EBCR-fired EGUs that have installed any downstream acid gas controls in addition to limestone injection into the FBC in response to the 2012 MATS rule. Further, the EPA has confirmed that extending the time horizon through March 2019 to include emissions data that have become available since the analysis for the 2019 Proposal would not result in changes to average SO2 lb/MMBtu emission rates for the currently operating EBCR-fired EGUs nor to the SO2 emission limit of 0.6 lb/MMBtu that, on average, those EGUs have achieved for that time period.25 Contrary to some comments, the beyond-the-floor analysis does recognize that each EBCR-fired EGU in the subcategory has controls to address acid gas emissions and, as explained earlier, average SO2 lb/MMBtu emission rates reflect those controls. In addition, the 2019 Proposal, as well as section 25 Including EBCR-fired EGUs’ SO emissions 2 data for the time period of July 2018 through March 2019 results in minor changes to average SO2 emissions values for some EBCR-fired EGUs but does not result in a change to the beyond-the-floor emission limit for SO2 lb/MMBtu. Nevertheless, the more recent SO2 data is included in an addendum to the 2019 Proposal’s analysis, titled NESHAP for Coal- and Oil-Fired EGUs: Addendum to MACT Floor Analysis and Beyond the MACT Floor Analysis for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs Under Consideration, available in Docket ID No. EPA–HQ– OAR–2018–0794. E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations III.A of this preamble, point out that all coal refuse fuels are fired in FBC that use limestone injection to minimize SO2 emissions and to increase heat transfer efficiency. As discussed in section III.A of this preamble, commenters have pointed out, however, that there are limitations on the ability of existing EBCR-fired EGUs to control acid gas emissions to the level of the 2012 final MATS acid gas standard by increasing the amount of limestone injected. As such, the EPA disagrees with comments claiming that the current controls are sufficient to meet the 2012 final MATS acid gas standard and that, therefore, the only relevant cost for purposes of any beyond-the-floor standard is the cost of operating (rather than installing) the control. As also discussed in section III.A of this preamble, commenters have pointed out feasibility issues associated with installation and operation of various downstream acid gas control technologies in order to meet the 2012 final MATS acid gas standard. For those same reasons, the EPA determined that downstream acid gas control technologies such as scrubbers (either wet FGD scrubbers or SDA) or DSI systems are not beyond-the-floor options for acid gas HAP emissions from the subcategory of existing EBCR-fired EGUs.26 Based on a review of the public comments and other available information, the EPA is finalizing HCl and SO2 emission limits reflecting beyond-the-floor level of control using the methodology described in the 2019 Proposal and earlier in this section of the preamble. Specifically, this action establishes the following emission limits for the new subcategory of existing EBCR-fired EGUs: HCl: 4.0E–2 lb/MMBtu or 4.0E–1 lb/MWh SO2: 27 6.0E–1 lb/MMBtu or 9.0 lb/MWh jbell on DSKJLSW7X2PROD with RULES The SO2 lb/MMBtu emissions limit is a limit that, on average, the currently operating EBCR-fired EGUs have achieved based on their monthly emissions data for January 2015 through 26 See, also, the memorandum titled NESHAP for Coal- and Oil-Fired EGUs: Addendum to MACT Floor Analysis and Beyond the MACT Floor Analysis for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs Under Consideration, available in Docket ID No. EPA–HQ– OAR–2018–0794. 27 As is the requirement for all coal-fired EGUs subject to MATS, the alternate SO2 limit may be used if the EGU has some form of FGD system and SO2 CEMS and both are installed and operated at all times. As specified in 40 CFR 63.10000(c)(1)(v) of the 2012 MATS final rule, limestone injection to an FBC unit is an ‘‘FGD system’’ that would allow the EBCR-fired EGUs to use the alternative SO2 standard. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 June 2018.28 Because the EPA does not have such HCl emissions data or SO2 lb/ MWh emissions data, beyond-the-floor standards for SO2 in lb/MWh and for HCl in lb/MMBtu and lb/MWh are based on the percentage reduction in the SO2 lb/MMBtu emissions rate between the MACT floor value and the beyondthe-floor value. IV. Summary of Cost, Environmental, and Economic Impacts and Additional Analyses Conducted A. What are the affected sources? Affected sources are EGUs that are in the unit designed for eastern bituminous coal refuse (EBCR) subcategory, as defined under this final action. Based on available information, there are six currently operating EBCR-fired EGUs that are in the newly established subcategory and subject to the newly established acid gas HAP emission standards. The six EGUs, located at three facilities in Pennsylvania and one facility in West Virginia, are listed in Table 2 of this preamble. B. What are the air quality impacts? Absent the subcategory finalized in this action, many affected EBCR-fired EGUs would likely discontinue operations. Although the new emission standards will allow higher acid gas HAP and SO2 emissions from these facilities compared to the emission standards in the original 2012 MATS, emissions of other HAP will not change under this action. These higher allowable emissions may, however, be partially offset. In the absence of this rule, closure of the units would likely result in reduced remediation of abandoned mine lands (AMLs) and potentially increase the risk and impact of emissions from refuse piles. Refuse piles at AMLs are prone to spontaneous internal combustion (smoldering) which emits uncontrolled air pollutants including acid gases and other HAP, and with less remediation, the potential for greater emissions from smoldering increases. More detailed analysis of potential air impacts of this rule is presented in a docketed memorandum.29 28 As previously explained in this preamble, at the time of the 2019 Proposal’s analysis, SO2 data through June 2018 were available. Inclusion of data that has become available only after the 2019 Proposal does not result in a change to the beyondthe-floor emission limit for SO2 lb/MMBtu. See the memorandum titled NESHAP for Coal- and OilFired EGUs: Addendum to MACT Floor Analysis and Beyond the MACT Floor Analysis for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs Under Consideration, available in Docket ID No. EPA–HQ–OAR–2018–0794. 29 See the memorandum titled Analysis of Potential Costs and Benefits for the National PO 00000 Frm 00037 Fmt 4700 Sfmt 4700 20847 C. What are the compliance cost impacts? Relative to a baseline in which the subcategory is not finalized and the existing 2012 MATS acid gas HAP emissions limits are enforced, the new subcategory could reduce costs by eliminating the need for investment in additional compliance measures which have not yet been made by affected units. The magnitude of potential cost reductions is discussed in a docketed memorandum.30 D. What are the economic impacts? The impact of the newly finalized subcategory of EBCR-fired EGUs for emissions of acid gas HAP on the broader electricity sector is likely to be minor due to the relatively small size of these facilities. Additionally, the risk of the affected EBCR-fired EGUs closing because of challenges in meeting MATS acid gas HAP limits is reduced by the new subcategory. As a result, the coal refuse reclamation services the units provide are more likely to be sustained in the future, potentially offsetting reclamation costs that may be otherwise incurred by the states of Pennsylvania and West Virginia. Additionally, because of the reduced risk of closure, the acid gas HAP subcategory finalized in this action could prevent labor market transitions for individuals who operate and perform support functions for these facilities. However, it may limit labor market opportunities that could result from AML reclamation by other means. E. What are the forgone benefits? Absent the subcategory finalized in this action, affected EBCR-fired EGUs would likely either discontinue operations or perform compliance measures to comply with the previous MATS acid gas HAP limits, which would have the effect of reducing acid gas HAP emissions. The newly finalized subcategory will likely increase emissions of SO2 relative to a baseline in which the subcategory is not finalized; this in turn would form fine PM (PM2.5) concentrations in the atmosphere and potentially adversely affect human health. The magnitude of those forgone co-benefits depends on the magnitude of the air quality impacts described earlier. Notably, most counties in Pennsylvania and bordering Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Subcategory of Certain Existing Electric Utility Steam Generating Units Firing Eastern Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air Pollutants, available in Docket ID No. EPA–HQ–OAR–2018–0794 30 Ibid. E:\FR\FM\15APR1.SGM 15APR1 jbell on DSKJLSW7X2PROD with RULES 20848 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations states attain the current PM2.5 National Ambient Air Quality Standards (NAAQS), set at a level requisite to protect public health with an adequate margin of safety. The magnitude of potential forgone benefits is discussed in a docketed memorandum.31 In contrast, if plants continue to operate when they otherwise would not have absent this action, the continued remediation of AMLs could provide water quality co-benefits through reductions in toxic metal leaching and acid mine drainage. As noted earlier, removal of coal refuse piles reduces surface and groundwater pollution from acidic drainage and reduces uncontrolled emissions of air pollutants that are released from self-ignited internal smoldering of the coal refuse piles. In addition, commenters pointed out that the alkaline ash produced by EBCR-fired EGUs is used to reclaim mining-affected lands by returning them to a productive use. Remediation of AMLs through the use of waste coal is supported by the state of Pennsylvania through policies such as tax credits and treatment of these units as renewable for purposes of the state’s renewable portfolio standard. If these waste coal units are no longer able to operate, the state will need to find alternative means to remediate these sites leading to, at best, a delay in these benefits, if not a loss of these benefits altogether. These benefits are discussed qualitatively in greater detail in the docketed memorandum. As noted earlier, while the EPA cannot predict with certainty what the industry response would be absent the establishment of a new subcategory, industry commenters have suggested that some—and maybe all—of the affected sources would shut down.32 If that is the case, then the establishment of this new subcategory will allow those units to continue to achieve both of their purposes while also maintaining emissions of acid gas HAP at levels similar to current emissions levels. While the EPA cannot predict with certainty what the industry response would be in the absence of a new subcategory, commenters’ claim that the units would shut down is plausible. Coal-fired power plants are currently facing tremendous competitive pressures. As a result, coal’s share of total U.S. electricity generation has been declining for over a decade, while generation from natural gas and renewables has increased significantly. 31 Ibid. 32 See EPA Docket ID Item Nos. EPA–HQ–OAR– 2018–0794–1125 and EPA–HQ–OAR–2018–0794– 1154. VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 A large number of coal units—especially smaller ones like the EBCR-fired EGUs—have retired since 2010. Indeed, as mentioned earlier, four of the ten units that were identified as affected by this action in the 2019 Proposal have now either retired or announced plans to convert to natural gas. V. Statutory and Executive Order Reviews Additional information about these statutes and Executive Orders can be found at https://www.epa.gov/lawsregulations/laws-and-executive-orders. A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review This action is an economically significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA has conducted an analysis of all reasonably anticipated costs and benefits arising out of this rule, including those arising out of co-benefits pursuant to Executive Orders 12866 and 13563. That analysis can be found in a separate memorandum titled Analysis of Potential Costs and Benefits for the National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units—Subcategory of Certain Existing Electric Utility Steam Generating Units Firing Eastern Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air Pollutants, that is available in the docket. B. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs This action is considered an Executive Order 13771 deregulatory action. This final rule provides meaningful burden reduction by revising the acid gas HAP emission standards for a new subcategory of certain existing EGUs that are currently subject to MATS and does not impose any additional regulatory requirements on the affected electric utility industry. C. Paperwork Reduction Act (PRA) This action does not impose any new information collection burden under the PRA. OMB has previously approved the information collection activities contained in the existing regulations and has assigned OMB control number 2060–0567. This action does not impose an information collection burden because the regulatory changes resulting PO 00000 Frm 00038 Fmt 4700 Sfmt 4700 from this action do not affect the currently approved information collection requirements. Specifically, this action establishes acid gas HAP emission standards for a new subcategory of certain existing EGUs that are currently subject to MATS and the new emission standards do not result in any changes to the recordkeeping or reporting requirements that those impacted EGUs are currently subject to. D. Regulatory Flexibility Act (RFA) I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden, or otherwise has a positive economic effect on the small entities subject to the rule. This is a deregulatory action, and the burden on all entities affected by this final rule, including small entities, is reduced compared to the 2012 MATS. E. Unfunded Mandates Reform Act (UMRA) This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. The action imposes no enforceable duty on any state, local or tribal governments or the private sector. F. Executive Order 13132: Federalism This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government. G. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This action does not have tribal implications as specified in Executive Order 13175. It will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. Specifically, this action establishes acid gas HAP emission standards for a new subcategory of certain existing EGUs currently subject to MATS and located in Pennsylvania and West Virginia, states without any federally recognized tribal entities. Thus, E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations Executive Order 13175 does not apply to this action. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA consulted with tribal officials during the development of this action. The EPA held consultations with the Blue Lake Rancheria and the Fond du Lac Band of Lake Superior Chippewa on April 2, 2019, and April 3, 2019, respectively. Neither tribe provided comments regarding the 2019 Proposal’s solicitation of comment on establishing a subcategory of certain existing EGUs firing EBCR for acid gas HAP emissions. jbell on DSKJLSW7X2PROD with RULES H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 because the EPA does not believe the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. While children may experience forgone benefits as a result of this action, the potential forgone emission reductions (and related benefits) from the final amendments are small compared to the overall emission reductions (and related benefits) from the 2012 MATS. Furthermore, this action does not affect the level of public health and environmental protection already being provided by existing NAAQS and other mechanisms in the CAA. This action does not affect applicable local, state, or federal permitting or air quality management programs that will continue to address areas with degraded air quality and maintain the air quality in areas meeting current standards. Areas that need to reduce criteria air pollution to meet the NAAQS will still need to rely on control strategies to reduce emissions. To the extent that states use other mechanisms in order to comply with the NAAQS, and still achieve the criteria pollution reductions that would have otherwise occurred, this action will not have a disproportionate adverse effect on children’s health. I. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a ‘‘significant energy action’’ because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, the EPA concludes that this action is not likely to have any adverse energy effects because it establishes acid gas HAP emission standards for a new subcategory of certain existing EGUs VerDate Sep<11>2014 16:09 Apr 14, 2020 Jkt 250001 that are currently subject to MATS and does not impose any additional regulatory requirements on the affected electric utility industry. J. National Technology Transfer and Advancement Act (NTTAA) This action does not involve technical standards. K. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations The EPA believes that this action does not have disproportionately high and adverse human health or environmental effects on minority populations, lowincome populations, and/or indigenous peoples, as specified in Executive Order 12898 (59 FR 7629, February 16, 1994). While these communities may experience forgone benefits as a result of this action, the potential forgone emission reductions (and related benefits) from the final action are small compared to the overall emission reductions (and related benefits) from the 2012 MATS. Moreover, this action does not affect the level of public health and environmental protection already being provided by existing NAAQS, including ozone and PM2.5, and other mechanisms in the CAA. This action does not affect applicable local, state, or federal permitting or air quality management programs that will continue to address areas with degraded air quality and maintain the air quality in areas meeting current standards. Areas that need to reduce criteria air pollution to meet the NAAQS will still need to rely on control strategies to reduce emissions. L. Congressional Review Act (CRA) This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. The CRA allows the issuing agency to make a rule effective sooner than otherwise provided by the CRA if the agency makes a good cause finding under the provisions of 5 U.S.C. 808(2). The EPA finds that there is good cause under the provisions of 5 U.S.C. 808(2) to make this final rule effective without full, prior Congressional review under 5 U.S.C. 801 and to make the rule effective on April 15, 2020. The EPA finds that it is unnecessary to delay the date this rule could be effective because the Agency has determined that the owners or operators of affected MATS sources do not need time to adjust to this final action. This final action establishes a subcategory of certain existing EGUs firing EBCR and acid gas PO 00000 Frm 00039 Fmt 4700 Sfmt 4700 20849 HAP emission standards applicable only to the new subcategory. Sources in the new subcategory will be subject to an SO2 emissions limit that, on average, the currently operating six EBCR-fired EGUs have demonstrated an ability to achieve but, otherwise, will not be subject to any new regulatory requirements.33 The EPA also finds that it is impracticable to delay the effective date of this rule. Three of the four facilities with EBCR-fired EGUs in the new subcategory are subject to EPA-issued Administrative Compliance Orders that provide interim SO2 emission limits that terminate on April 15, 2020. Those facilities have asserted that they cannot meet the 2012 final MATS HCl emission standard, or the 2012 final MATS SO2 acid gas HAP surrogate emission standard, while burning the coal refuse fuel for which their facilities were designed. By 11:59 p.m. on April 15, 2020, EBCR-fired EGUs at those facilities must achieve full compliance with MATS. Absent this final action’s acid gas HAP emission standards for the new subcategory being effective by that date, EGUs at those three facilities would be subject to the 2012 final MATS acid gas HAP emission standards that they are not currently in compliance with, and, thus, in violation of their Orders. According to the facilities, if subject to the 2012 acid gas HAP emission standards, they would no longer be in a position to continue operating their EBCR-fired EGUs and, thus, provide the environmental benefits associated with removal of coal refuse piles and reclamation and remediation of mining-affected lands. Accordingly, the EPA finds it would be unnecessary and impracticable to delay the effective date of this action and that there is good cause to dispense with the opportunity for a 60-day period of prior Congressional review and to publish this final rule with an effective date of April 15, 2020. List of Subjects in 40 CFR Part 63 Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Intergovernmental relations, Reporting and recordkeeping requirements. Andrew Wheeler, Administrator. For the reasons set forth in the preamble, the Environmental Protection Agency amends 40 CFR part 63 as follows: 33 Affected sources may report emissions of either SO2 or HCl. Most MATS-affected EGUs report emissions of SO2 because they already report SO2 emissions under the EPA’s Acid Rain Program. E:\FR\FM\15APR1.SGM 15APR1 20850 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES 1. The authority citation for part 63 continues to read as follows: ■ Authority: 42 U.S.C. 7401, et seq. Subpart UUUUU—National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units 2. Section 63.9982 is amended by revising paragraph (d) to read as follows: ■ § 63.9982 What is the affected source of this subpart? * * * * * (d) An EGU is existing if it is not new or reconstructed. An existing electric steam generating unit that meets the applicability requirements after April 16, 2012, due to a change in process (e.g., fuel or utilization) is considered to be an existing source under this subpart. ■ 3. Section 63.9984 is amended by revising paragraphs (b) and (f) and adding paragraph (g) to read as follows: § 63.9984 When do I have to comply with this subpart? * * * * * (b) If you have an existing EGU, you must comply with this subpart no later than April 16, 2015, except as provided in paragraph (g) of this section. * * * * * (f) You must demonstrate that compliance has been achieved, by conducting the required performance tests and other activities, no later than 180 days after the applicable date in paragraph (a), (b), (c), (d), (e), or (g) of this section. (g) If you own or operate an EGU that is in the Unit designed for eastern bituminous coal refuse (EBCR) subcategory as defined in § 63.10042, you must comply with the applicable hydrogen chloride (HCl) or sulfur dioxide (SO2) requirements of this subpart no later than April 15, 2020. ■ 4. Section 63.9990 is amended by revising paragraph (a) to read as follows: § 63.9990 EGUs? What are the subcategories of (a) Coal-fired EGUs are subcategorized as defined in paragraphs (a)(1) through (3) of this section and as defined in § 63.10042. (1) EGUs designed for coal with a heating value greater than or equal to 8,300 Btu/lb, (2) EGUs designed for low rank virgin coal, and (3) EGUs designed for EBCR. * * * * * ■ 5. Section 63.10042 is amended by adding definitions for ‘‘Eastern bituminous coal refuse (EBCR),’’ ‘‘Net summer capacity,’’ and ‘‘Unit designed for eastern bituminous coal refuse (EBCR) subcategory’’ in alphabetical order to read as follows: If your EGU is in this subcategory . . . For the following pollutants . . . 1. Coal-fired unit not low rank virgin coal a. Filterable particulate matter (PM). OR Total non-Hg HAP metals OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... jbell on DSKJLSW7X2PROD with RULES Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... VerDate Sep<11>2014 16:59 Apr 14, 2020 Jkt 250001 PO 00000 Frm 00040 Fmt 4700 § 63.10042 subpart? What definitions apply to this * * * * * Eastern bituminous coal refuse (EBCR) means coal refuse generated from the mining of bituminous coal in Pennsylvania and West Virginia. * * * * * Net summer capacity means the maximum output, commonly expressed in megawatts (MW), that generating equipment can supply to system load, as demonstrated by a multi-hour test, at the time of summer peak demand (period of June 1 through September 30.) This output reflects a reduction in capacity due to electricity use for station service or auxiliaries. * * * * * Unit designed for eastern bituminous coal refuse (EBCR) subcategory means any existing (i.e., construction was commenced on or before May 3, 2011) coal-fired EGU with a net summer capacity of no greater than 150 MW that is designed to burn and that is burning 75 percent or more (by heat input) eastern bituminous coal refuse on a 12month rolling average basis. * * * * * ■ 6. Table 2 to Subpart UUUUU of Part 63 is revised to read as follows: Table 2 to Subpart UUUUU of Part 63— Emission Limits for Existing EGUs As stated in § 63.9991, you must comply with the following applicable emission limits: 1 You must meet the following emission limits and work practice standards . . . Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 3.0E–2 lb/MMBtu or 3.0E– 1 lb/MWh 2. OR 5.0E–5 lb/MMBtu or 5.0E– 1 lb/GWh. OR ............................................ 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.1E0 lb/TBtu or 2.0E–2 lb/ GWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. 2.8E0 lb/TBtu or 3.0E–2 lb/ GWh. 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 4.0E0 lb/TBtu or 5.0E–2 lb/ GWh. 3.5E0 lb/TBtu or 4.0E–2 lb/ GWh. Collect a minimum of 1 dscm per run. Sfmt 4700 E:\FR\FM\15APR1.SGM Collect a minimum of 1 dscm per run. Collect a minimum of 3 dscm per run. 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations If your EGU is in this subcategory . . . You must meet the following emission limits and work practice standards . . . For the following pollutants . . . Selenium (Se) .................... b. Hydrogen chloride (HCl) OR ..................................... Sulfur dioxide (SO2) 4 ........ c. Mercury (Hg) ................. 5.0E0 lb/TBtu or 6.0E–2 lb/ GWh. 2.0E–3 lb/MMBtu or 2.0E– 2 lb/MWh. ............................................ 2.0E–1 lb/MMBtu or 1.5E0 lb/MWh. 1.2E0 lb/TBtu or 1.3E–2 lb/ GWh. OR 1.0E0 lb/TBtu or 1.1E–2 lb/ GWh. 2. Coal-fired unit low rank virgin coal ........ a. Filterable particulate matter (PM). OR Total non-Hg HAP metals OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... Selenium (Se) .................... b. Hydrogen chloride (HCl) jbell on DSKJLSW7X2PROD with RULES OR Sulfur dioxide (SO2) 4 ........ c. Mercury (Hg) ................. VerDate Sep<11>2014 16:59 Apr 14, 2020 Jkt 250001 PO 00000 Frm 00041 Fmt 4700 3.0E–2 lb/MMBtu or 3.0E– 1 lb/MWh 2. OR 5.0E–5 lb/MMBtu or 5.0E– 1 lb/GWh. OR ............................................ 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.1E0 lb/TBtu or 2.0E–2 lb/ GWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. 2.8E0 lb/TBtu or 3.0E–2 lb/ GWh. 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 4.0E0 lb/TBtu or 5.0E–2 lb/ GWh. 3.5E0 lb/TBtu or 4.0E–2 lb/ GWh. 5.0E0 lb/TBtu or 6.0E–2 lb/ GWh. 2.0E–3 lb/MMBtu or 2.0E– 2 lb/MWh. 2.0E–1 lb/MMBtu or 1.5E0 lb/MWh. 4.0E0 lb/TBtu or 4.0E–2 lb/ GWh. Sfmt 4700 E:\FR\FM\15APR1.SGM 20851 Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . For Method 26A at appendix A–8 to part 60 of this chapter, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320 at appendix A to part 63 of this chapter, sample for a minimum of 1 hour. SO2 CEMS. LEE Testing for 30 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B at appendix A–8 to part 60 of this chapter run or Hg CEMS or sorbent trap monitoring system only. LEE Testing for 90 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. Collect a minimum of 1 dscm per run. Collect a minimum of 1 dscm per run. Collect a minimum of 3 dscm per run. For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26 at appendix A–8 to part 60 of this chapter, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. SO2 CEMS. LEE Testing for 30 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 15APR1 20852 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations If your EGU is in this subcategory . . . For the following pollutants . . . 3. IGCC unit ............................................... a. Filterable particulate matter (PM). OR Total non-Hg HAP metals OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... Selenium (Se) .................... b. Hydrogen chloride (HCl) 4. Liquid oil-fired unit—continental (excluding limited-use liquid oil-fired subcategory units). 3.0E–2 lb/MMBtu or 3.0E– 1 lb/MWh 2. OR Total HAP metals .............. OR 8.0E–4 lb/MMBtu or 8.0E– 3 lb/MWh. OR ............................................ 1.3E+1 lb/TBtu or 2.0E–1 lb/GWh. 2.8E0 lb/TBtu or 3.0E–2 lb/ GWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 5.5E0 lb/TBtu or 6.0E–2 lb/ GWh. 2.1E+1 lb/TBtu or 3.0E–1 lb/GWh. 8.1E0 lb/TBtu or 8.0E–2 lb/ GWh. 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh. 1.1E+2 lb/TBtu or 1.1E0 lb/ GWh. 3.3E0 lb/TBtu or 4.0E–2 lb/ GWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... jbell on DSKJLSW7X2PROD with RULES Collect a minimum of 1 dscm per run. a. Filterable particulate matter (PM). Beryllium (Be) .................... Selenium (Se) .................... Mercury (Hg) ..................... Jkt 250001 4.0E–2 lb/MMBtu or 4.0E– 1 lb/MWh 2. OR 6.0E–5 lb/MMBtu or 5.0E– 1 lb/GWh. OR ............................................ 1.4E0 lb/TBtu or 2.0E–2 lb/ GWh. 1.5E0 lb/TBtu or 2.0E–2 lb/ GWh. 1.0E–1 lb/TBtu or 1.0E–3 lb/GWh. 1.5E–1 lb/TBtu or 2.0E–3 lb/GWh. 2.9E0 lb/TBtu or 3.0E–2 lb/ GWh. 1.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 1.9E+2 lb/TBtu or 1.8E0 lb/ GWh. 2.5E0 lb/TBtu or 3.0E–2 lb/ GWh. 6.5E0 lb/TBtu or 7.0E–2 lb/ GWh. 2.2E+1 lb/TBtu or 3.0E–1 lb/GWh. 5.0E–4 lb/MMBtu or 5.0E– 3 lb/MWh. 2.5E0 lb/TBtu or 3.0E–2 lb/ GWh. Arsenic (As) ....................... 16:59 Apr 14, 2020 Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . c. Mercury (Hg) ................. OR Individual HAP metals: ...... Antimony (Sb) .................... VerDate Sep<11>2014 You must meet the following emission limits and work practice standards . . . PO 00000 Frm 00042 Fmt 4700 Sfmt 4700 E:\FR\FM\15APR1.SGM Collect a minimum of 1 dscm per run. Collect a minimum of 2 dscm per run. For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. LEE Testing for 30 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. Collect a minimum of 1 dscm per run. Collect a minimum of 1 dscm per run. Collect a minimum of 1 dscm per run. For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1 2 the standard. 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations If your EGU is in this subcategory . . . 5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units). You must meet the following emission limits and work practice standards . . . Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . b. Hydrogen chloride (HCl) 2.0E–3 lb/MMBtu or 1.0E– 2 lb/MWh. c. Hydrogen fluoride (HF) .. 4.0E–4 lb/MMBtu or 4.0E– 3 lb/MWh. a. Filterable particulate matter (PM). 3.0E–2 lb/MMBtu or 3.0E– 1 lb/MWh 2. For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. Collect a minimum of 1 dscm per run. OR Total HAP metals .............. OR 6.0E–4 lb/MMBtu or 7.0E– 3 lb/MWh. OR ............................................ 2.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 4.3E0 lb/TBtu or 8.0E–2 lb/ GWh. 6.0E–1 lb/TBtu or 3.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. 3.1E+1 lb/TBtu or 3.0E–1 lb/GWh. 1.1E+2 lb/TBtu or 1.4E0 lb/ GWh. 4.9E0 lb/TBtu or 8.0E–2 lb/ GWh. 2.0E+1 lb/TBtu or 3.0E–1 lb/GWh. 4.7E+2 lb/TBtu or 4.1E0 lb/ GWh. 9.8E0 lb/TBtu or 2.0E–1 lb/ GWh. 4.0E–2 lb/TBtu or 4.0E–4 lb/GWh. For the following pollutants . . . OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... Selenium (Se) .................... Mercury (Hg) ..................... 6. Solid oil-derived fuel-fired unit ............... b. Hydrogen chloride (HCl) 2.0E–4 lb/MMBtu or 2.0E– 3 lb/MWh. c. Hydrogen fluoride (HF) .. 6.0E–5 lb/MMBtu or 5.0E– 4 lb/MWh. a. Filterable particulate matter (PM). OR Total non-Hg HAP metals 8.0E–3 lb/MMBtu or 9.0E– 2 lb/MWh 2. OR 4.0E–5 lb/MMBtu or 6.0E– 1 lb/GWh. OR ............................................ 8.0E–1 lb/TBtu or 7.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 5.0E–3 lb/GWh. 6.0E–2 lb/TBtu or 5.0E–4 lb/GWh. 3.0E–1 lb/TBtu or 4.0E–3 lb/GWh. 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh. 1.1E0 lb/TBtu or 2.0E–2 lb/ GWh. OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... jbell on DSKJLSW7X2PROD with RULES Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ VerDate Sep<11>2014 16:59 Apr 14, 2020 Jkt 250001 20853 PO 00000 Frm 00043 Fmt 4700 Sfmt 4700 E:\FR\FM\15APR1.SGM Collect a minimum of 1 dscm per run. Collect a minimum of 2 dscm per run. For Method 30B sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < 1 2 the standard. For Method 26A, collect a minimum of 1 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 2 hours. For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 2 hours. Collect a minimum of 1 dscm per run. Collect a minimum of 1 dscm per run. Collect a minimum of 3 dscm per run. 15APR1 20854 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations If your EGU is in this subcategory . . . You must meet the following emission limits and work practice standards . . . For the following pollutants . . . Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... Selenium (Se) .................... b. Hydrogen chloride (HCl) OR Sulfur dioxide (SO2) 4 ........ c. Mercury (Hg) ................. 7. Eastern Bituminous (EBCR)-fired unit. Coal Refuse a. Filterable particulate matter (PM). OR Total non-Hg HAP metals OR Individual HAP metals: ...... Antimony (Sb) .................... Arsenic (As) ....................... Beryllium (Be) .................... Cadmium (Cd) ................... Chromium (Cr) ................... Cobalt (Co) ........................ Lead (Pb) ........................... Manganese (Mn) ............... Nickel (Ni) .......................... Selenium (Se) .................... b. Hydrogen chloride (HCl) OR Sulfur dioxide (SO2) 4 ........ jbell on DSKJLSW7X2PROD with RULES c. Mercury (Hg) ................. 8.0E–1 lb/TBtu or 2.0E–2 lb/GWh. 2.3E0 lb/TBtu or 4.0E–2 lb/ GWh. 9.0E0 lb/TBtu or 2.0E–1 lb/ GWh. 1.2E0 lb/Tbtu or 2.0E–2 lb/ GWh. 5.0E–3 lb/MMBtu or 8.0E– 2 lb/MWh. 3.0E–1 lb/MMBtu or 2.0E0 lb/MWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 3.0E–2 lb/MMBtu or 3.0E– 1 lb/MWh 2. OR 5.0E–5 lb/MMBtu or 5.0E– 1 lb/GWh. OR ............................................ 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.1E0 lb/TBtu or 2.0E–2 lb/ GWh. 2.0E–1 lb/TBtu or 2.0E–3 lb/GWh. 3.0E–1 lb/TBtu or 3.0E–3 lb/GWh. 2.8E0 lb/TBtu or 3.0E–2 lb/ GWh. 8.0E–1 lb/TBtu or 8.0E–3 lb/GWh. 1.2E0 lb/TBtu or 2.0E–2 lb/ GWh. 4.0E0 lb/TBtu or 5.0E–2 lb/ GWh. 3.5E0 lb/TBtu or 4.0E–2 lb/ GWh. 5.0E0 lb/TBtu or 6.0E–2 lb/ GWh. 4.0E–2 lb/MMBtu or .......... 4.0E–1 lb/MWh .................. 6E–1 lb/MMBtu or 9E0 lb/ MWh. 1.2E0 lb/TBtu or 1.3E–2 lb/ GWh. Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320, sample for a minimum of 1 hour. SO2 CEMS. LEE Testing for 30 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. Collect a minimum of 1 dscm per run. Collect a minimum of 1 dscm per run. Collect a minimum of 3 dscm per run. For Method 26A at appendix A–8 to part 60 of this chapter, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348–03 3 or Method 320 at appendix A to part 63 of this chapter, sample for a minimum of 1 hour. SO2 CEMS. LEE Testing for 30 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B at appendix A–8 to part 60 of this chapter run or Hg CEMS or sorbent trap monitoring system only. OR VerDate Sep<11>2014 16:59 Apr 14, 2020 Jkt 250001 PO 00000 Frm 00044 Fmt 4700 Sfmt 4700 E:\FR\FM\15APR1.SGM 15APR1 Federal Register / Vol. 85, No. 73 / Wednesday, April 15, 2020 / Rules and Regulations If your EGU is in this subcategory . . . For the following pollutants . . . 20855 You must meet the following emission limits and work practice standards . . . Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) and limitations with the test methods in Table 5 to this Subpart . . . 1.0E0 lb/TBtu or 1.1E–2 lb/ GWh. LEE Testing for 90 days with a sampling period consistent with that given in section 5.2.1 of appendix A to this subpart per Method 30B run or Hg CEMS or sorbent trap monitoring system only. 1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must be increased nominally by a factor of 2. 2 Gross output. 3 Incorporated by reference, see § 63.14. 4 You may not use the alternate SO limit if your EGU does not have some form of FGD system and SO CEMS installed. 2 2 [FR Doc. 2020–07878 Filed 4–14–20; 8:45 am] BILLING CODE 6560–50–P ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [EPA–HQ–OAR–2018–0417; FRL–10006–80– OAR] RIN 2060–AT74 National Emission Standards for Hazardous Air Pollutants: Hydrochloric Acid Production Residual Risk and Technology Review Environmental Protection Agency (EPA). ACTION: Final rule. AGENCY: This action finalizes the residual risk and technology review (RTR) conducted for the Hydrochloric Acid (HCl) Production source category regulated under national emission standards for hazardous air pollutants (NESHAP). In addition, in this action we are finalizing amendments to add electronic reporting; address periods of startup, shutdown, and malfunction (SSM); and establish work practice standards for maintenance activities pursuant to the Clean Air Act (CAA). We are making no revisions to the numerical emission limits based on the risk analysis or technology review. Although these amendments are not anticipated to result in reductions in emissions of hazardous air pollutants (HAP), they will result in improved monitoring, compliance and implementation of the rule. DATES: This final rule is effective on April 15, 2020. ADDRESSES: The U.S. Environmental Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA–HQ–OAR–2018–0417. All documents in the docket are listed on the https://www.regulations.gov/ jbell on DSKJLSW7X2PROD with RULES SUMMARY: VerDate Sep<11>2014 16:59 Apr 14, 2020 Jkt 250001 website. Although listed in the index, some information is not publicly available, e.g., Confidential Business Information or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through https://www.regulations.gov/, or in hard copy at the EPA Docket Center, WJC West Building, Room Number 3334, 1301 Constitution Ave., NW, Washington, DC. The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m., Eastern Standard Time (EST), Monday through Friday. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the Docket Center is (202) 566–1742. FOR FURTHER INFORMATION CONTACT: For questions about this final action, contact Nathan Topham, Sector Policies and Programs Division (D243–02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541– 0483; fax number: (919) 541–4991; and email address: topham.nathan@epa.gov. For specific information regarding the risk modeling methodology, contact Terri Hollingsworth, Health and Environmental Impacts Division (C539– 02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541–5623; fax number: (919) 541–0840; and email address: hollingsworth.terri@epa.gov. For information about the applicability of the NESHAP to a particular entity, contact Marcia Mia, Office of Enforcement and Compliance Assurance, U.S. Environmental Protection Agency, WJC South Building (Mail Code 2227A), 1200 Pennsylvania PO 00000 Frm 00045 Fmt 4700 Sfmt 4700 Ave. NW, Washington, DC 20460; telephone number: (202) 564–7042; and email address: mia.marcia@epa.gov. SUPPLEMENTARY INFORMATION: 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, the EPA defines the following terms and acronyms here: CAA Clean Air Act CDX Central Data Exchange Cl2 chlorine ERT Electronic Reporting Tool HAP hazardous air pollutants(s) HCl hydrochloric acid HI hazard index HQ hazard quotient IARC International Agency for Research on Cancer ICR Information Collection Request MACT maximum achievable control technology MIR maximum individual risk NAAQS National Ambient Air Quality Standards NESHAP national emission standards for hazardous air pollutants NTTAA National Technology Transfer and Advancement Act RFA Regulatory Flexibility Act RTR Risk and Technology Review TOSHI target organ-specific hazard index UMRA Unfunded Mandates Reform Act Background information. On February 4, 2019, the EPA proposed the results of the RTR for the HCl NESHAP and proposed amendments to add electronic reporting and address periods of SSM. In the proposal, the EPA also solicited public comments regarding maintenance activities. In this action, we are finalizing decisions and revisions for the rule. We summarize some of the more significant comments we timely received regarding the proposed rule and provide our responses in this preamble. A summary of all other public comments on the proposal and the EPA’s responses to those comments is available in the Summary of Public Comments and E:\FR\FM\15APR1.SGM 15APR1

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 85, Number 73 (Wednesday, April 15, 2020)]
[Rules and Regulations]
[Pages 20838-20855]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-07878]


-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2018-0794; FRL-10007-26-OAR]
RIN 2060-AU48


National Emission Standards for Hazardous Air Pollutants: Coal- 
and Oil-Fired Electric Utility Steam Generating Units--Subcategory of 
Certain Existing Electric Utility Steam Generating Units Firing Eastern 
Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air 
Pollutants

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The U.S. Environmental Protection Agency (EPA) is taking final 
action establishing a subcategory of certain existing electric utility 
steam generating units (EGUs) firing eastern bituminous coal refuse 
(EBCR) for acid gas hazardous air pollutant (HAP) emissions that was 
noticed in a February 7, 2019, proposed rule titled ``National Emission 
Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric 
Utility Steam Generating Units--Reconsideration of Supplemental Finding 
and Residual Risk and Technology Review'' (2019 Proposal). After 
consideration of public comments, the EPA has determined that there is 
a need for such a subcategory under the National Emission Standards for 
Hazardous Air Pollutants (NESHAP) for Coal- and Oil-Fired EGUs, 
commonly known as the Mercury and Air Toxics Standards (MATS), and the 
Agency is establishing acid gas HAP emission standards applicable only 
to the new subcategory. The EPA's final decisions on the other two 
distinct actions in the 2019 Proposal (i.e., reconsideration of the 
2016 Supplemental Finding that it is appropriate and necessary to 
regulate EGUs under Clean Air Act (CAA) section 112 and the residual 
risk and technology review of MATS) will be announced in a separate 
final action.

DATES: This final rule is effective on April 15, 2020.

ADDRESSES: The EPA has established a docket for this action under 
Docket ID No. EPA-HQ-OAR-2018-0794. All documents in the docket are 
listed on the https://www.regulations.gov/ website. Although listed, 
some information is not publicly available, e.g., confidential business 
information or other information whose disclosure is restricted by 
statute. Certain other material, such as copyrighted material, is not 
placed on the internet and will be publicly available only in hard copy 
form. Publicly available docket materials are available either 
electronically through https://www.regulations.gov/, or in hard copy at 
the EPA Docket Center, Room Number 3334, WJC West Building, 1301 
Constitution Ave. NW, Washington, DC. The Public Reading Room hours of 
operation are 8:30 a.m. to 4:30 p.m., Eastern Standard Time (EST), 
Monday through Friday. 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.

FOR FURTHER INFORMATION CONTACT: For questions about this final action, 
contact Mary Johnson, Sector Policies and Programs Division (D243-01), 
Office of Air Quality Planning and Standards, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711; 
telephone number: (919) 541-5025; and email address: 
[email protected]. For information about the applicability of the 
NESHAP to a particular entity, contact your EPA Regional representative 
as listed in 40 CFR 63.13 (General Provisions).

SUPPLEMENTARY INFORMATION: 
    Preamble acronyms and abbreviations. The EPA uses multiple acronyms 
and terms in this preamble. While this list may not be exhaustive, to 
ease the reading of this preamble and for reference purposes, the EPA 
defines the following terms and acronyms here:

ARIPPA Appalachian Region Independent Power Producers Association
CAA Clean Air Act
CEMS continuous emissions monitoring systems
CFR Code of Federal Regulations
CRA Congressional Review Act
DSI dry sorbent injection
EBCR eastern bituminous coal refuse
ECMPS Emissions Collection and Monitoring Plan System
EGU electric utility steam generating unit
EPA Environmental Protection Agency
FBC fluidized bed combustors

[[Page 20839]]

FGD flue gas desulfurization
HAP hazardous air pollutant(s)
HCl hydrochloric acid
Hg mercury
ICR Information Collection Request
lb pound
lb/MMBtu pounds per million British thermal units
lb/MWh pounds per megawatt-hour
MACT maximum achievable control technology
MATS Mercury and Air Toxics Standards
MMBtu million British thermal units
MW megawatt
MWh megawatt-hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PM particulate matter
PM2.5 fine particulate matter
PRA Paperwork Reduction Act
RFA Regulatory Flexibility Act
SDA spray dryer absorbers
SO2 sulfur dioxide
tpy tons per year
UMRA Unfunded Mandates Reform Act

Organization of this document. The information in this preamble is 
organized as follows:

I. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. Where can I get a copy of this document and other related 
information?
    D. Judicial Review and Administrative Reconsideration
II. Background
III. Summary of Final Action
    A. Basis for Subcategory
    B. Subcategory Emission Standards
IV. Summary of Cost, Environmental, and Economic Impacts and 
Additional Analyses Conducted
    A. What are the affected sources?
    B. What are the air quality impacts?
    C. What are the compliance cost impacts?
    D. What are the economic impacts?
    E. What are the forgone benefits?
V. 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 Regulations 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
    L. Congressional Review Act (CRA)

I. General Information

A. Executive Summary

    In the 2012 MATS rulemaking, the EPA established one subcategory of 
coal-fired EGUs for purposes of regulating acid gas HAP emissions. The 
Agency specifically rejected a request from some commenters for a 
separate acid gas HAP standard for all coal refuse-fired EGUs because 
we determined that the emissions of such HAP from some units combusting 
coal refuse were among the best performing sources for acid gas HAP as 
determined consistent with CAA section 112(d)(3). The EPA has 
reevaluated the data available when the 2012 MATS rule was established, 
in addition to new data generated since promulgation of that rule, and 
we now recognize that there are differences in the acid gas HAP 
emissions from EGUs firing EBCR as compared to EGUs firing other types 
of coal, including those firing types of coal refuse other than EBCR. 
Specifically, the EPA recognizes that there are differences between 
anthracite coal refuse and bituminous coal refuse, and that the type of 
fuel used leads to differences in the acid gas HAP emissions from EGUs 
firing those respective fuels. In the February 7, 2019 Proposal (84 FR 
2670), the EPA explained that these differences in acid gas HAP 
emissions support the establishment of a subcategory for such sources 
and solicited comment on the need to establish a subcategory of certain 
existing EGUs firing EBCR for acid gas HAP emissions and on potential 
emissions standards for affected EGUs in that subcategory. After 
reviewing public comments and other available information, the EPA 
concludes that such a subcategory is warranted. Thus, this final action 
establishes a subcategory of certain existing EBCR-fired EGUs for 
emissions of hydrochloric acid (HCl) and sulfur dioxide 
(SO2)--both of which serve as a surrogate for all acid gas 
HAP emitted from EGUs under MATS. Under CAA section 112(d)(1), the EPA 
has the discretion to ``. . . distinguish among classes, types, and 
sizes of sources within a category or subcategory in establishing . . . 
standards.'' Further, when separate subcategories are established, the 
minimum level of control, referred to as the ``maximum achievable 
control technology (MACT) floor,'' is determined separately for each 
subcategory.
    The EPA has determined that emission limits reflecting a more 
stringent (i.e., ``beyond-the-floor'') level of control than the MACT 
floor level of control are appropriate for the new subcategory. The 
SO2 emission standard (set in pounds (lb) SO2/
million British thermal units (MMBtu)) that the EPA is promulgating 
here is an emission rate that the currently operating EBCR-fired EGUs 
have demonstrated an ability to achieve based on their emissions data 
and considering cost and non-air quality related environmental 
factors.\1\ The EPA does not have corresponding emissions data for HCl 
\2\ or output-based emissions of SO2 (i.e., lb 
SO2/megawatt-hour (MWh)) and, therefore, the EPA has 
established the final beyond-the-floor standards for SO2 (in 
lb/MWh) and for HCl (in both lb/MMBtu and lb/MWh) consistent with the 
percentage reduction in the SO2 lb/MMBtu emissions rate 
between the MACT floor value and the beyond-the-floor value. This 
action establishes the following emission limits for the subcategory of 
existing EBCR-fired EGUs: \3\
---------------------------------------------------------------------------

    \1\ For context, the 2012 final MATS emission standard for 
SO2 is 2.0E-1 lb/MMBtu.
    \2\ For MATS, affected sources may report emissions of either 
SO2 or HCl. Most MATS-affected EGUs report emissions of 
SO2 because they already have the monitoring 
infrastructure to do so, since most already report SO2 
emissions under the EPA's Acid Rain Program.
    \3\ Continuous compliance with the emission limits is required 
to be demonstrated on a 30-boiler operating day rolling average 
basis.

HCl: 4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh
SO2: \4\ 6.0E-1 lb/MMBtu or 9.0 lb/MWh.
---------------------------------------------------------------------------

    \4\ As is the requirement for all coal-fired EGUs subject to 
MATS, the alternate SO2 limit may be used if the EGU has 
some form of flue gas desulfurization (FGD) system and 
SO2 continuous emissions monitoring systems (CEMS) and 
both are installed and operated at all times.

    A further description of what the EPA is promulgating here, the 
rationale for the final decisions, and discussion of the key comments 
received regarding the need for such a subcategory and the acid gas HAP 
emission standards appropriate for that subcategory are provided in 
section III of this preamble.

B. Does this action apply to me?

    Categories and entities potentially regulated by this action are 
shown in Table 1 of this preamble.

[[Page 20840]]



 Table 1--Neshap and Industrial Source Categories Affected by This Final
                                 Action
------------------------------------------------------------------------
               NESHAP and source  category                NAICS code \a\
------------------------------------------------------------------------
Coal- and Oil-Fired EGUs................................  221112, 221122
------------------------------------------------------------------------
\a\ North American Industry Classification System.

    Table 1 of this preamble is not intended to be exhaustive, but 
rather to provide a guide for readers regarding entities likely to be 
affected by the final action for the source category listed. 
Specifically, entities that own and/or operate certain existing EBCR-
fired EGUs subject to the NESHAP for Coal- and Oil-Fired EGUs (40 CFR 
part 63, subpart UUUUU) will be affected by this final action. To 
determine whether your facility is affected, you should examine the 
applicability criteria in the NESHAP for Coal- and Oil-Fired EGUs and 
the amendatory text of this final action. If you have any questions 
regarding the applicability of any aspect of this NESHAP, please 
contact the appropriate person listed in the preceding FOR FURTHER 
INFORMATION CONTACT section of this preamble.

C. 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, the EPA will post a copy of this final action at 
https://www.epa.gov/mats/regulatory-actions-final-mercury-and-air-toxics-standards-mats-power-plants. Following publication in the 
Federal Register, the EPA will post the Federal Register version of the 
final rule and key technical documents at this same website.

D. Judicial Review and Administrative Reconsideration

    Under CAA section 307(b)(1), judicial review of this final action 
is available only by filing a petition for review in the United States 
Court of Appeals for the District of Columbia Circuit (hereafter 
referred to as ``the D.C. Circuit,'' or ``the Court'') by June 15, 
2020. Under CAA section 307(b)(2), the requirements established by this 
final rule may not be challenged separately in any civil or criminal 
proceedings brought by the EPA to enforce the requirements.
    Section 307(d)(7)(B) of the CAA further provides that only an 
objection to a rule or procedure which was raised with reasonable 
specificity during the period for public comment (including any public 
hearing) may be raised during judicial review. This section also 
provides a mechanism for the EPA to reconsider the rule if the person 
raising an objection can demonstrate to the Administrator that it was 
impracticable to raise such objection within the period for public 
comment or if the grounds for such objection arose after the period for 
public comment (but within the time specified for judicial review) and 
if such objection is of central relevance to the outcome of the rule. 
Any person seeking to make such a demonstration should submit a 
Petition for Reconsideration to the Office of the Administrator, U.S. 
EPA, Room 3000, WJC South Building, 1200 Pennsylvania Ave. NW, 
Washington, DC 20460, with a copy to both the person(s) listed in the 
preceding FOR FURTHER INFORMATION CONTACT section of this preamble, and 
the Associate General Counsel for the Air and Radiation Law Office, 
Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 
Pennsylvania Ave. NW, Washington, DC 20460.

II. Background

    The NESHAP for Coal- and Oil-Fired EGUs (commonly referred to as 
MATS) was proposed on May 3, 2011 (76 FR 24976), under title 40, part 
63, subpart UUUUU. In that proposal, the EPA proposed a single acid gas 
HAP emission standard for all coal-fired power plants--using HCl as a 
surrogate for all acid gas HAP. The EPA also proposed an alternative 
equivalent emission standard for SO2 as a surrogate for all 
the acid gas HAP for coal-fired EGUs with FGD systems and 
SO2 CEMS installed and operational at all times. 
SO2 is also an acidic gas--though not a HAP--and the 
controls used for SO2 emission reduction are also effective 
at controlling the acid gas HAP emitted by EGUs. Further, most, if not 
all, affected EGUs already measure and report SO2 emissions 
as a requirement of the EPA's Acid Rain Program, 40 CFR part 75.
    The Appalachian Region Independent Power Producers Association 
(ARIPPA) \5\ submitted comments on the 2011 MATS proposal arguing that 
the characteristics of all coal refuse made achievement of the standard 
too costly for its members and requested that the EPA create a 
subcategory for all EGUs burning coal refuse. The EPA determined that 
there was no basis to create such a subcategory and, on February 16, 
2012 (77 FR 9304), finalized emission standards for both HCl and 
SO2 that apply to all coal-fired EGUs, including the coal 
refuse-fired units subject to this final action. ARIPPA, along with 
other petitioners, challenged the EPA's determination in the D.C. 
Circuit, and the Court upheld the final rule. White Stallion Energy 
Center, et. al. v. EPA, 748 F.3d 1222, 1249-50 (D.C. Cir. 2014).
---------------------------------------------------------------------------

    \5\ ARIPPA is a non-profit trade association comprised of 
independent electric power producers, environmental remediators, and 
service providers located in Pennsylvania and West Virginia that use 
coal refuse as a primary fuel to generate electricity.
---------------------------------------------------------------------------

    In addition to challenging the final rule, ARIPPA also petitioned 
the EPA for reconsideration, again requesting a subcategory for the 
acid gas standards for facilities combusting all types of coal refuse. 
The EPA denied the Petition for Reconsideration on grounds that ARIPPA 
had adequate opportunity to comment on the ability of coal refuse-fired 
facilities to comply with the final standard. Furthermore, the EPA 
determined that the ARIPPA petition did not present any new information 
to support a change in the previous determination regarding the 
appropriateness of a subcategory for the acid gas HAP standard. ARIPPA 
subsequently sought judicial review of the denial of the Petition for 
Reconsideration. ARIPPA v. EPA, No. 15-1180 (D.C. Cir.).\6\ In 
petitioner's briefs, ARIPPA claimed that the EPA had misunderstood its 
reconsideration petition and pointed to a distinction between the 
control of acid gas HAP emissions from units burning anthracite coal 
refuse and those burning bituminous coal refuse. See Industry Pets. Br. 
at 35-36, ARIPPA, No. 15-1180 (D.C. Cir. filed December 6, 2016). The 
EPA disagrees with the assertion that the Agency misunderstood the 
basis for ARIPPA's reconsideration petition as we could not find a 
single statement in the rulemaking record that clearly or even vaguely 
requested a separate acid gas HAP limit based on the distinction 
between anthracite coal refuse and bituminous coal refuse. Nonetheless, 
the EPA has since looked at emissions data from these sources and 
observed that there are differences in emissions based on the type of 
coal refuse used, and, consequently, recognized the differences in the 
2019 Proposal.\7\ Specifically, the EPA recognized that there are 
differences between anthracite coal refuse and bituminous coal refuse, 
and that the type of fuel used leads to differences in the acid gas HAP

[[Page 20841]]

emissions from EGUs firing those respective fuels. The Agency also 
noted that the differences may impact the unit's ability to control 
those emissions. Additionally, the EPA recognized that there are 
differences between western bituminous coal refuse and subbituminous 
coal refuse as compared to EBCR and announced in the 2019 Proposal that 
it was considering establishing a subcategory of certain existing EGUs 
firing EBCR for emissions of acid gas HAP. The proposal solicited 
comment on whether establishment of such a subcategory is needed and on 
the acid gas HAP emission standards that would be established if such a 
subcategory was created. 84 FR 2700-2703.
---------------------------------------------------------------------------

    \6\ ARIPPA's petition for review is currently being held in 
abeyance. ARIPPA v. EPA, No. 15-1180, Order, No. 1672985 (April 27, 
2017).
    \7\ The analysis is summarized in a separate memorandum titled 
HCl and SO2 Emissions for Coal Refuse-Fired EGUs, 
available in Docket ID No. EPA-HQ-OAR-2018-0794.
---------------------------------------------------------------------------

III. Summary of Final Action

    After considering and evaluating comments and data provided in 
response to the solicitation of comment on establishing a subcategory 
of certain existing EGUs firing EBCR for emissions of acid gas HAP in 
its 2019 Proposal, the EPA is taking final action to establish a 
separate subcategory to address the issue. In this final action, the 
EPA is establishing a subcategory of certain existing EGUs firing EBCR 
for emissions of acid gas HAP and acid gas HAP emission standards that 
are applicable to the new subcategory. The final rule defines Eastern 
bituminous coal refuse (EBCR) to mean coal refuse generated from the 
mining of bituminous coal in Pennsylvania and West Virginia. The final 
rule defines Unit designed for eastern bituminous coal refuse (EBCR) 
subcategory to mean any existing (i.e., construction was commenced on 
or before May 3, 2011) coal-fired EGU with a net summer capacity of no 
greater than 150 megawatts (MW) that is designed to burn and that is 
burning 75 percent or more (by heat input) eastern bituminous coal 
refuse on a 12-month rolling average basis. The 150 MW net summer 
capacity level selected by the EPA limits the universe of sources that 
are in the new subcategory to only those EGUs identified in Table 2 to 
this preamble. Net summer capacity is the maximum output that 
generating equipment can supply to system load at the time of summer 
peak demand (period of June 1 through September 30). The 75 percent or 
more heat input requirement selected by the EPA is consistent with the 
Federal Energy Regulatory Commission requirement that to be considered 
a qualifying facility under the Public Utility Regulatory Policies Act, 
as the EGUs in the new subcategory are, at least 75 percent of the heat 
content must come from coal refuse.
    The existing EBCR-fired EGUs in the new subcategory being 
established in this action are listed in Table 2 of this preamble and 
the applicable HCl and SO2 limits being finalized in this 
action are provided in Table 3 of this preamble. Four existing EBCR-
fired EGUs at two facilities that were listed in the 2019 Proposal as 
being part of the new subcategory, if established, are no longer part 
of the subcategory. The EPA has learned that the Cambria facility shut 
down in June 2019, and the facility and surrounding property have been 
sold to a salvage company which plans to dismantle the facility over 
time.\8\ The EPA has also learned that the Morgantown Energy facility 
will be transformed into a natural gas-fueled steam-only production 
facility, and the closure of the waste coal-fired boilers and complete 
transformation of the facility to steam-only production are expected to 
be completed by early to mid-2020.\9\
---------------------------------------------------------------------------

    \8\ See https://www.tribdem.com/news/cambria-cogen-plant-to-be-leveled-after-shutting-down-over/article_005a162c-2381-11ea-8c53-5b85339774fd.html.
    \9\ See https://www.nsenergybusiness.com/news/starwood-energy-terminates-eepa/.

                                     Table 2--EBCR-Fired EGUs in Subcategory
----------------------------------------------------------------------------------------------------------------
                                                                                                   2016 average
                                                                                      Summer          monthly
         ORIS plant code \a\                     EGU                  State        capacity (MW)    generation
                                                                                                     (MWh) \b\
----------------------------------------------------------------------------------------------------------------
10143................................  Colver Power Project...  PA                           110          60,905
10151................................  Grant Town Power Plant   WV                            40          28,010
                                        Unit 1A.
10151................................  Grant Town Power Plant   WV                            40          28,010
                                        Unit 1B.
10603................................  Ebensburg Power........  PA                            50          16,258
50974................................  Scrubgrass Generating    PA                            42          17,377
                                        Company LP Unit 1.
50974................................  Scrubgrass Generating    PA                            42          17,377
                                        Company LP Unit 2.
----------------------------------------------------------------------------------------------------------------
\a\ Unique plant identification code assigned by the Department of Energy's Energy Information Administration
  (EIA).
\b\ 2016 annual generation is based on plant-level data reported on EIA Form 923, and annual totals are divided
  evenly to estimate 2016 average monthly generation. Unit-level estimates assume that generation is split
  evenly between all units at each plant.


 Table 3--Acid Gas Emission Limitations for EBCR-Fired EGUs Subcategory
------------------------------------------------------------------------
                                            Emission limit \a\
           Subcategory           ---------------------------------------
                                          HCl               SO2 \b\
------------------------------------------------------------------------
Existing Eastern Bituminous Coal  4.0E-2 lb/MMBtu...  6.0E-1 lb/MMBtu
 Refuse-Fired EGUs.
                                  or                  or
                                  4.0E-1 lb/MWh.....  9.0 lb/MWh
------------------------------------------------------------------------
\a\ Units of emission limits:
lb/MMBtu = pounds pollutant per million British thermal units fuel
  input; and
lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
\b\ Alternate SO2 limit may be used if the EGU has some form of FGD
  system and SO2 CEMS installed.

    Sources in the new subcategory must comply with the applicable HCl 
or SO2 requirements no later than the effective date of this 
final rule. Sources must demonstrate that compliance has been achieved, 
by conducting the required performance tests and other activities as 
specified in 40 CFR part 60, subpart UUUUU, no later than 180 days 
after the compliance date. To demonstrate initial compliance using 
either an HCl or SO2 CEMS, the initial performance test

[[Page 20842]]

consists of 30-boiler operating days. If the CEMS is certified prior to 
the compliance date, the test begins with the first operating day on or 
after that date. If the CEMS is not certified prior to the compliance 
date, the test begins with the first operating day after certification 
testing is successfully completed. Continuous compliance with the newly 
established emission limits is required to be demonstrated on a 30-
boiler operating day rolling average basis.
    The EPA's final decisions regarding establishing a subcategory for 
certain existing EGUs that fire EBCR and the acid gas HAP standards 
applicable to the new subcategory are provided later in this section of 
this preamble. Specifically, the EPA's rationale for the final 
decisions and discussion relating to the key comments received 
regarding the need for such a subcategory and the attendant acid gas 
HAP emission standards are provided. A summary of all significant 
public comments regarding the EPA's consideration of establishing such 
a subcategory and the EPA's responses to those comments is available in 
the document titled Summary of Public Comments and Responses Regarding 
Establishment of a Subcategory and Acid Gas HAP Emission Standards for 
Certain Existing Eastern Bituminous Coal Refuse-Fired EGUs (response to 
comments document), Docket ID No. EPA-HQ-OAR-2018-0794. A ``track 
changes'' version of the regulatory language that incorporates the 
changes in this action is also available in the docket for this action.

A. Basis for Subcategory

    Under CAA section 112(d)(1), the Administrator has discretion to 
``* * * distinguish among classes, types, and sizes of sources within a 
category or subcategory in establishing * * *'' standards. Based on the 
EPA's better understanding of the differences in anthracite coal refuse 
and bituminous coal refuse, and the acid gas HAP emissions profile 
associated with each, the EPA has now determined that, contrary to its 
earlier position, it is appropriate to establish a new subcategory for 
certain units firing EBCR. Specifically, the EPA is establishing a new 
subcategory for certain units with a net summer capacity of 150 MW or 
lower that fire EBCR because there are differences between emissions of 
acid gas HAP from these units and larger units burning EBCR and units 
burning other types of coal, including other types of coal refuse. See 
U.S. Sugar Corp. v. EPA, 830 F.3d 579, 656 (DC Cir. 2016) (finding that 
``[s]ection 7412(d) gives the EPA discretion to create subcategories 
based on boiler type, and nothing in the statute forecloses the Agency 
from doing so based on the type of fuel a boiler was designed to 
burn.''). Units in this new subcategory of EGUs are smaller, were 
designed to burn EBCR, and were constructed in close proximity to 
legacy piles of EBCR for the primary purposes of reclaiming abandoned 
mining sites while reducing the environmental hazards attendant to such 
piles of coal refuse. The EPA cannot predict with certainty what the 
industry response would be absent the establishment of a new 
subcategory as discussed in greater detail elsewhere in this preamble 
and in a docketed memorandum on expected costs and benefits. Among 
those possible outcomes, many industry commenters and others have 
suggested that some--and maybe all--of the affected sources would shut 
down.\10\ If that is the case, then the establishment of this new 
subcategory will allow those units to continue to achieve both of their 
purposes of reclaiming abandoned mining sites and preserving the 
environmental benefits of repurposing coal refuse, while also 
maintaining emissions of acid gas HAP at levels similar to current 
emissions levels.\11\
---------------------------------------------------------------------------

    \10\ While the EPA cannot predict with certainty what the 
industry response would be in the absence of a new subcategory, 
commenters' claims that the units would shut down is plausible. 
Coal-fired power plants are currently facing tremendous competitive 
pressures. As a result, coal's share of total U.S. electricity 
generation has been declining for over a decade, while generation 
from natural gas and renewables has increased significantly. A large 
number of coal units--especially smaller ones like the EBCR-fired 
EGUs--have retired since 2010. As mentioned earlier, four of the ten 
units that were identified as affected by this action in the 2019 
Proposal have now either retired or announced plans to convert to 
natural gas.
    \11\ EBCR-fired EGUs were designed to achieve a control level 
generally at or exceeding 90 percent SO2 reduction (see 
EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1125, EPA-HQ-OAR-2018-
0794-1154, and EPA-HQ-OAR-2018-0794-1187).
---------------------------------------------------------------------------

    Immediately below and in the response to comments document, we 
discuss in more detail the basis for the new subcategory and address 
the significant comments on the new subcategory.
    As stated in the 2019 Proposal, the EPA finds that the emissions of 
acid gas HAP from EGUs firing EBCR are distinct from acid gas HAP 
emissions from EGUs firing other types of coal--including other forms 
of coal refuse. Specifically, the EPA recognized in the 2019 Proposal 
that there are differences between anthracite coal refuse and 
bituminous coal refuse, and that the type of fuel used leads to 
differences in the acid gas HAP emissions from EGUs firing those 
respective fuels. Bituminous coals (and, thus, bituminous coal refuse) 
from the Appalachian and Interior Regions of the U.S. have higher 
sulfur and chlorine contents than anthracite or coals of all types from 
the Western Region of the U.S. (and, thus, anthracite coal refuse or 
western bituminous and subbituminous coal refuse), and these 
differences lead to differences in emissions of acid gas HAP. These 
differences between the types of coal refuse used by EGUs to generate 
electricity may also impact a unit's ability to control those 
emissions. All coal refuse fuels are fired in fluidized bed combustors 
(FBC) that use limestone injection to reduce SO2 emissions 
and to increase heat transfer efficiency. The EPA has been informed 
that limestone injection technology is generally adequate to allow EGUs 
that are firing anthracite coal refuse and western coal refuse to meet 
the 2012 final MATS alternative surrogate emission standard of 2.0E-1 
lb/MMBtu for SO2.\12\ This is because anthracite coals are 
naturally much lower in impurities (including sulfur and chlorine) and 
western coals (western bituminous coal and subbituminous coal) have 
lower sulfur and chlorine content and higher free alkalinity (which can 
act as a natural sorbent to neutralize acid gases produced in the 
combustion process). The same is not generally true for EGUs combusting 
EBCR. Because all existing EGUs firing anthracite coal refuse and 
western bituminous coal refuse are currently emitting SO2 at 
rates that are below the 2012 final MATS emission standard for 
SO2 and the existing EGU firing subbituminous coal refuse is 
currently emitting HCl at a rate that is below the 2012 final MATS 
emission standard for HCl, the EPA believes there is no need to broaden 
the subcategory to include those units.
---------------------------------------------------------------------------

    \12\ See Table 2 to subpart UUUUU of 40 CFR part 63.
---------------------------------------------------------------------------

    The EBCR-fired EGUs that will be included in the new subcategory 
are also small units (all have capacities less than 120 MW and most are 
less than 100 MW). As contemplated in the 2019 Proposal, this final 
rule excludes the two EBCR-fired EGUs at the Seward Generating Station 
in Pennsylvania from the new subcategory. 84 FR 2702. Those units are 
the newest and, at 260 MW each, are, by far, the largest coal refuse-
fired EGUs. The Seward units were also designed and constructed with 
downstream acid gas controls already incorporated, so they do not have 
the space limitations and other configurational challenges that may

[[Page 20843]]

affect other smaller existing EBCR-fired EGUs attempting to retrofit 
air pollution controls. Retrofitting air pollution controls to an 
existing EGU can often be challenging due to lack of available space 
within the facility and the potential need to re-route the exhaust gas 
stream to accommodate such equipment configurational changes. Control 
equipment that results in pressure drop along the exhaust stream can 
challenge existing blowers. These challenges and space limitations can 
be considered in the design of a new facility. The Seward units were 
among the best performing EGUs--with respect to HCl emissions--when the 
EPA developed the final MATS emission standards and, based on MATS 
compliance reports for the Seward EGUs, currently emit HCl at well 
below the final MATS HCl standard of 2.0E-3 lb/MMBtu, applicable to 
coal-fired EGUs.\13\
---------------------------------------------------------------------------

    \13\ Ibid.
---------------------------------------------------------------------------

    In response to the 2019 Proposal's solicitation of comment, the EPA 
received comments both supporting and opposing the establishment of a 
subcategory of certain existing EGUs firing EBCR for emissions of acid 
gas HAP.
    Several commenters pointed out the environmental benefits provided 
by EBCR-fired EGUs in the coal regions where they are located. 
Specifically, commenters pointed out that removal of coal refuse piles 
reduces surface and groundwater pollution from acidic drainage and 
reduces uncontrolled emissions of air pollutants that are released from 
self-ignited internal smoldering of the coal refuse piles. In addition, 
commenters pointed out that the alkaline ash produced by EBCR-fired 
EGUs is used to reclaim mining-affected lands by returning them to a 
productive use. Commenters further noted that the Pennsylvania 
Department of Environmental Protection has standards governing such 
beneficial use of coal ash in mine land reclamation (Title 25 PA Code, 
Chapter 290).\14\
---------------------------------------------------------------------------

    \14\ See https://www.dep.pa.gov/Business/Land/Mining/BureauofMiningPrograms/Pages/CoalAshBeneficialUse.aspx.
---------------------------------------------------------------------------

    Several commenters asserted that the 2012 final MATS limits for 
acid gas HAP and their SO2 surrogate are not achievable by 
EBCR-fired EGUs and do not reflect the design, functionality, and 
economics of those units. Commenters stated that while limestone 
injection into the unit's combustion zone controls SO2 and 
HCl emissions to a certain extent, there are operational and design 
limitations on the EGUs' ability to provide an adequate amount of 
limestone to reduce SO2 and HCl emissions beyond a certain 
point. Commenters further stated that the reduction of SO2 
and acid gases through increased injection of limestone is asymptotic, 
and significant additional limestone does not result in further 
significant acid gas emission reduction. Commenters explained that the 
configuration of the EGUs and their combustion zone physically limit 
the amount of material that the unit can hold, which impacts and limits 
the amount of coal refuse and limestone that can be injected into the 
unit. Commenters explained, for example, that increasing the amount of 
limestone injected to achieve the 2012 final MATS SO2 
emission limit could result in less coal refuse being fired. This would 
result in a corresponding reduction in steam production and electricity 
generation, making it uneconomic to operate in the current power 
market.
    The EPA does not have detailed information regarding the specific 
amount of limestone that is injected into the EBCR-fired EGUs. However, 
the Agency acknowledges that it is current industry practice to inject 
limestone into the FBC in amounts based on an optimized calcium-to-
sulfur (Ca:S) molar ratio. Therefore, the optimum limestone injection 
amount will vary with the sulfur content of the coal refuse being 
burned. Along with the coal (fuel) and limestone that are injected and 
utilized, the fluidized bed units also contain an inert bed material 
(e.g., sand or other). There is a limit to the amount of solid 
material--i.e., the sand, the coal refuse, coal ash, and limestone--
that can be in the combustor. An increase in limestone injection may 
necessarily result in a decrease in coal refuse utilization. 
Utilization of the limestone for acid gas neutralization is dependent 
upon decomposition (calcination) of the limestone to lime and 
subsequent reaction of the lime with the acid gases via the following 
reactions:

CaCO3 + heat [rarr] CaO + CO2
SO2 + CaO [rarr] CaSO3
2HCl + CaO [rarr] CaCl2 + H2O

    The necessary calcination of the limestone and the desulfurization 
reactions occur within specific temperature ranges (typically around ~ 
900 [deg]Celsius or 1,650 [deg]F) and the FBC operators must utilize 
sufficient fuel to maintain the boiler in the optimum temperature 
range. Lower temperatures result in insufficient calcination and lower 
boiler efficiency. Higher temperatures can result in materials 
sintering, which results in lower desulfurization capacity.
    Commenters also noted concerns that a significant increase in 
limestone injection for control of SO2 emissions could 
negatively impact the ability to beneficially use the combustion fly 
ash.\15\ For example, for certain uses, the Pennsylvania Department of 
Environmental Protection Guidelines for Beneficial Use of Coal Ash at 
Coal Mines \16\ warns that mixing of coal ash with conventional 
alkaline materials (e.g., limestone, lime, hydrated lime) may increase 
the likelihood of the coal ash becoming cementitious and reduce the 
neutralizing ability of the coal ash and the conventional material. In 
such cases, the captured fly ash would have to be disposed of in a 
lined landfill rather than beneficially reused. Commenters also 
contended that EBCR-fired EGUs may have to consider switching from EBCR 
as the primary fuel to firing less EBCR along with a lower sulfur fuel 
as a means of reducing SO2 emissions to meet the 2012 final 
MATS SO2 emission limit. Commenters stated that such 
practice, in addition to being uneconomical, could reduce EBCR usage to 
below the minimum 75-percent coal refuse heat input requirement to be 
considered a qualifying facility under the Public Utility Regulatory 
Policies Act. Commenters claimed that both approaches described earlier 
(i.e., increased limestone injection and fuel switching) undermine the 
environmental benefits realized by the EBCR-fired EGUs through clean-up 
of waste coal refuse sites.
---------------------------------------------------------------------------

    \15\ The combustion ash is beneficially used on mine sites to 
fill pits, create or amend soil, and as a low-permeability or high 
alkalinity material. In Pennsylvania the regulations governing the 
beneficial use of coal ash are available at 25 PA Code Chapter 290. 
See https://www.dep.pa.gov/Business/Land/Mining/BureauofMiningPrograms/Pages/CoalAshBeneficialUse.aspx.
    \16\ Pennsylvania Department of Environmental Protection Bureau 
of Mining Programs; Document Number: 563-2112-228; Guidelines for 
Beneficial Use of Coal Ash at Coal Mines; Effective date: December 
17, 2016.
---------------------------------------------------------------------------

    One commenter stated that regardless of limestone addition and fuel 
switching, meeting the 2012 final MATS SO2 limit would 
require additional control technology and likely result in permanent 
retirement of the facility. Several commenters pointed out that they 
are not aware of any retrofit installation of back-end scrubbing 
technology or a back-end dry sorbent injection (DSI) system for an 
EBCR-fired EGU. Commenters asserted that downstream acid gas controls 
cannot be considered technically or economically feasible for EBCR-
fired EGUs and provided information regarding evaluation of such 
technologies.

[[Page 20844]]

Commenters claimed that adding on back-end control equipment would 
boost sulfur capture, but the capital and operating costs increases 
would not be supported by power sales revenues. Commenters further 
claimed that in addition to being cost prohibitive for the small EBCR 
units, control strategies such as wet FGD scrubbers and spray dryer 
absorbers (SDA) present installation difficulties given layout of the 
facilities, local topography, and needs of the systems to interface 
with existing EGU equipment.\17\ Although commenters acknowledged that 
DSI systems do not present such technical challenges with deployment, 
they pointed out other problems associated with the alkaline sorbents 
(typically sodium- or calcium-based) injected in such systems. Several 
commenters stated that coal refuse-fired EGUs currently achieve 
extremely efficient mercury (Hg) control due, at least in part, to the 
relatively high levels of chlorine in coal refuse which can promote the 
oxidation of the Hg to the divalent form. This, coupled with the higher 
levels of unburned carbon in the fly ash, allows the Hg to be more 
readily captured in the downstream baghouse (i.e., fabric filter 
particulate matter (PM) control device) and not emitted through the 
stack. Commenters explained that reducing the amount of chlorine (or 
HCl) in the flue gas prior to the oxidation reaction can have the 
effect of increasing Hg emissions from the facility. One commenter 
stated that their testing of both sodium- and calcium-based sorbents 
injected at the inlet of the baghouse (essentially in a DSI 
configuration) resulted in an increase in Hg emissions by a factor of 4 
to 40 times resulting in levels exceeding the 2012 final MATS Hg 
emission limit.\18\ Therefore, the commenter asserted that, even if 
technically feasible, the use of DSI could affect the unit's ability to 
meet other MATS emission limits. Several commenters stated that the 
potential for DSI technology to have a negative impact on the ability 
to use combustion ash for mine site reclamation and restoration 
activities would remove it as a viable alternative. Commenters 
explained that use of sodium-based sorbents (e.g., trona or sodium 
bicarbonate) could alter the leaching characteristics of the ash such 
that it would no longer be of beneficial use and would have to be 
disposed of in a lined landfill. One commenter stated that testing at 
their facility confirmed such a change in the quality of the ash to the 
point that it was at risk of failing to satisfy leaching requirements 
of the standards for beneficial use in mine land reclamation. 
Commenters claimed that ash disposal costs, especially when considering 
the significant quantity of ash generated, would far exceed the revenue 
generated through the sale of electricity. Commenters also pointed out 
that significant environmental benefits provided by EBCR-fired EGUs 
would be eliminated if the ash cannot be beneficially used.
---------------------------------------------------------------------------

    \17\ See EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1154 and 
EPA-HQ-OAR-2018-0794-1160 for additional discussion of commenters' 
claims of physical and configurational difficulties in installing 
downstream control technologies.
    \18\ This testing is described in materials provided to the EPA 
by ARIPPA during a March 13, 2013, meeting. The materials are 
available in the previous MATS rulemaking Docket ID Item No. EPA-HQ-
OAR-2009-0234-20338 and in the current Docket ID No. EPA-HQ-OAR-
2018-0794.
---------------------------------------------------------------------------

    Several commenters asserted that there is no justification for 
establishing a subcategory of certain existing EGUs firing EBCR for 
emissions of acid gas HAP. Commenters claimed that the EPA has not 
provided a valid technical basis for the subcategory, stating that 
while the EPA has said that eastern bituminous coal is distinguished by 
higher sulfur content and lesser content of free alkali, the EPA offers 
nothing to distinguish the EGUs it would subcategorize from other EGUs 
burning the same coals and subject to MATS. Commenters further claimed 
that there is no basis for a subcategory for EBCR-fired EGUs because 
some of those EGUs currently emit SO2 at rates below the 
2012 final MATS SO2 limit and have shown that the current 
standards are achievable because there are technologies that are 
feasible. Commenters stated that the assessment of the need for a 
subcategory cannot reasonably be based on data for the period of 
January 2015 through June 2018, terminating before EGUs reported 
results of installed pollution controls. Commenters added that even if 
limestone injection alone is not adequate to meet the MATS limits, the 
fact that certain EGUs would need to install additional controls is not 
a valid basis for a subcategory. Commenters also added that the EPA may 
not subcategorize based on cost, even if some add-on controls would be 
particularly expensive, and the EPA may not alter the MACT floor 
because some sources may not be able to meet it. Commenters further 
stated that the EPA notes that the use of some sorbents may negatively 
impact the salability of fly ash, but commenters contend that losing 
the ability to sell the ash--a consequence for all EGUs using DSI, not 
just those using eastern bituminous coal-waste--does not suggest any 
basis in the class, type, or size of the EGUs at the six plants that 
might allow the EPA to set different standards for those EGUs. 
Commenters pointed to a plant within the proposed subcategory that they 
contend demonstrates that units can meet the MATS acid gas limits while 
still re-using their ash. Commenters refuted the EPA's assertion that 
use of DSI technology results in a considerable increase in Hg 
emissions and would require the use of additional Hg controls, and, 
further, stated that even if true, it provides no lawful basis for the 
subcategory. Commenters pointed to EBCR-fired EGUs that they contend 
not only can meet both the MATS acid gas and Hg limits, they can 
achieve such low emissions of Hg that they qualify for low-emitting EGU 
status (i.e., their emissions are less than 10 percent of the MATS 
limit) without any Hg-specific controls. Commenters added that CAA 
section 112 does not permit the EPA to loosen emission limitations 
based on the EPA's desired control configuration.
    The EPA disagrees with comments opposed to establishing a new 
subcategory of certain existing EGUs firing EBCR for emissions of acid 
gas HAP. Under CAA section 112(d)(1), the Administrator has the 
discretion to `` * * * distinguish among classes, types, and sizes of 
sources within a category or subcategory in establishing * * * '' 
standards. The EPA generally establishes subcategories to address 
differences between units that make the nature of the HAP emissions 
different or if there are technical feasibility issues associated with 
different emission control approaches. Normally, the basis for 
subcategorizing (e.g., type of unit) must be related to an effect on 
emissions, rather than some difference which does not affect emissions 
performance. EGUs are generally designed for a particular type of fuel, 
and the type of fuel being burned can impact the degree of combustion 
and the level and type of HAP emissions because the amount of fuel-
borne HAP such as acid gases is primarily dependent upon the 
composition of the fuel. In addition, the type of fuel and attendant 
unit design can limit the availability and functionality of different 
types of controls, particularly for existing sources that must retrofit 
if add-on controls are required. Finally, the D.C. Circuit recently 
confirmed that the EPA may establish a subcategory based on the type of 
fuel a boiler is designed to burn. See U.S. Sugar Corp. v. EPA, 830 
F.3d at 656. Consistent with the statute and case law, the EPA is 
establishing a subcategory based on the

[[Page 20845]]

size (boiler 150 MW or less) and type (boiler designed to burn EBCR) to 
address the different acid gas HAP emissions from such sources.
    To inform our consideration, the EPA reviewed EGU design, operating 
information, air emissions data compiled from the 2010 Information 
Collection Request (ICR) that was used by the EPA during development of 
the 2012 MATS final rule, and other available information for coal-
fired EGUs in the source category. The EPA found that there are 
significant design and operational differences in coal-fired EGUs that 
are based on the expected source of fuel and the design of the unit 
that affect the levels of emissions of HCl and SO2--both of 
which serve as a surrogate for all acid gas HAP emitted from coal-fired 
EGUs under MATS. These differences support our decision to establish a 
subcategory for existing EGUs that burn EBCR and have a net summer 
capacity of 150 MW or lower. Specifically, the emissions data for HCl 
and SO2 show a distinguishable difference in performance 
exists between coal-fired units with a net summer capacity of no 
greater than 150 MW designed to burn EBCR and other coal-fired units, 
including units that burn coal refuse other than EBCR.^{19 20} 
Because the EBCR-fired units have different emission characteristics 
for acid gas HAP, the EPA has determined that units that are designed 
to burn EBCR, and actually burn at least 75-percent EBCR, are a 
different type of unit and should be subcategorized for acid gas HAP 
emissions.\21\
---------------------------------------------------------------------------

    \19\ As discussed earlier in this section of this preamble, the 
subcategory being established in this final rule excludes the two 
EBCR-fired EGUs at the Seward Generating Station, which are 260 MW 
each, from the new subcategory.
    \20\ See the memorandum titled HCl and SO2 Emissions 
for Coal Refuse-Fired EGUs, available in Docket ID No. EPA-HQ-OAR-
2018-0794.
    \21\ For all other HAP from these two subcategories of coal-
fired units, the data did not show any difference in the level of 
the HAP emissions and, therefore, we have determined that it is not 
reasonable to establish separate emissions limits for the other HAP.
---------------------------------------------------------------------------

    The determination that EBCR-fired EGUs have different emission 
characteristics for acid gas HAP is reasonably based on the same 2010 
ICR dataset used to establish the bases of subcategories and standards 
in the 2012 MATS final rule. An examination of the data shows that 
there were no coal-fired units with a net summer capacity of 150 MW or 
less designed to burn EBCR among the top performing 12 percent of coal-
fired units for emissions of HCl or SO2, even though the EPA 
used 12 percent of the entire source category (130 units) to establish 
the acid gas HAP standard for coal-fired EGUs. There were, however, 
EGUs firing bituminous coal, subbituminous coal, and lignite among the 
top performing units for HCl and EGUs firing bituminous, subbituminous, 
lignite, and non-EBCR coal refuse among the top performers for 
SO2. The EPA points out that the assessment of the need for 
a subcategory was not based on data for the period of January 2015 
through June 2018 as suggested by commenters. As discussed in section 
III.B of this preamble, those data were used to determine the 
SO2 lb/MMBtu emission rate for beyond-the-floor level of 
control. The EPA disagrees with commenters' assertions that the fact 
that some EBCR-fired EGUs have met the 2012 final MATS SO2 
limit means the new subcategory is unreasonable. The EPA is aware of 
EGUs at two plants \22\ that have been able to meet the 2012 final MATS 
SO2 limit. Historical SO2 emissions data reported 
to the EPA's Emissions Collection and Monitoring Plan System (ECMPS) 
for those EGUs shows that those plants had lower SO2 
emissions than other EBCR-fired EGUs. Thus, the additional 
SO2 emissions reductions required for those EGUs to meet the 
2012 final MATS SO2 limit are more likely to be achievable 
through means such as increased limestone injection and fuel switching 
without the limitations described by several commenters and summarized 
earlier in this section of the preamble. The EPA's understanding, 
however, is that the operational changes made to those EGUs with 
historically lower SO2 emissions in order to meet the 2012 
final MATS SO2 limit result in less EBCR being disposed of 
and are not economically feasible in the long term. One facility has 
met the SO2 limit by injecting more limestone and the other 
facility has met the limit by co-firing lower sulfur coal. Similarly, 
the ability of those same units to meet the 2012 final MATS acid gas 
HAP limit as well as the Hg limit or to meet the 2012 final MATS acid 
gas HAP limit while still re-using their ash does not mean a separate 
subcategory is unwarranted or unreasonable. The information in the 
record supports a conclusion that the existing EGUs in the new 
subcategory are different from a fuel and design perspective and it is 
reasonable to establish a new subcategory based on the size and type of 
unit. In addition, this new subcategory is also reasonable because the 
alternative is to maintain a standard that requires the sources to 
operate in a manner that undermines the purpose for which they were 
constructed and may be technologically infeasible for certain units in 
the subcategory. Specifically, the coal refuse-fired EGUs at issue were 
constructed at or near legacy piles of EBCR for the primary purposes of 
reducing the health and environmental hazards associated with the coal 
piles and using the resultant coal ash to reclaim abandoned mining 
sites. The commenters in support of the rule provided information 
indicating the reasons the new subcategory is warranted and how 
requiring compliance with the 2012 MATS limit for acid gas HAP would 
undermine the continued viability of the EBCR-fired EGUs to perform 
both of these functions.
---------------------------------------------------------------------------

    \22\ Neither of these two plants with EBCR-fired EGUs that have 
met the 2012 final MATS SO2 limit are the Seward 
Generating Station discussed earlier in this section of this 
preamble.
---------------------------------------------------------------------------

    For all these reasons, we do not agree that the commenters have 
raised any significant objections to the EPA's determination that it is 
reasonable and appropriate to establish a new subcategory for EBCR-
fired EGUs. Accordingly, we are finalizing the new subcategory.

B. Subcategory Emission Standards

    As noted in the 2019 Proposal, the EPA conducted an analysis to 
determine the numerical acid gas emission standards for the subcategory 
of certain existing EGUs that fire EBCR should such a subcategory be 
established.\23\ The EPA explained that it determined the MACT floor 
and the beyond-the-floor (i.e., more stringent than the MACT floor) 
levels of control for HCl and SO2 emissions. The EPA further 
explained that the SO2 lb/MMBtu emission rate for beyond-
the-floor level of control was determined for each currently operating 
EBCR-fired EGU using monthly SO2 data available in the EPA's 
ECMPS for the period of January 2015 through June 2018.\24\ The EPA 
stated that if a beyond-the-floor (with floor at 1.0 lb/MMBtu) 
SO2 emissions limit was established, it would likely be in 
the range of 0.60-0.70 lb/MMBtu; a limit that, on average, the 
currently operating EBCR-fired EGUs have demonstrated an ability to

[[Page 20846]]

achieve based on their monthly emissions data for January 2015 through 
June 2018. The EPA explained that due to data limitations (i.e., no HCl 
lb/MMBtu or lb/MWh emissions data have been submitted for the currently 
operating EBCR-fired EGUs, and SO2 lb/MWh emissions data are 
available for only two of the currently operating EBCR-fired EGUs), 
this same beyond-the-floor methodology used to determine the beyond-
the-floor standards for SO2 in lb/MMBtu could not be used to 
evaluate beyond-the-floor standards for SO2 in lb/MWh or for 
HCl in either lb/MMBtu or lb/MWh. The EPA, therefore, further explained 
that it determined that beyond-the-floor standards for those 
pollutants, if established, should reasonably be set based on the same 
percentage reduction as the SO2 lb/MMBtu described earlier 
(i.e., the 40-percent reduction in the emissions rate for 
SO2 between the calculated MACT floor value of 1.0 lb/MMBtu 
and the beyond-the-floor value of 0.60 lb/MMBtu). The EPA solicited 
comment on the analysis conducted to determine the numerical acid gas 
emission standards and, on its methodology, and results. Table 4 of 
this preamble shows the results of the MACT floor and beyond-the-floor 
analyses as discussed in the 2019 Proposal.
---------------------------------------------------------------------------

    \23\ The analysis is summarized in a separate memorandum titled 
NESHAP for Coal- and Oil-Fired EGUs: MACT Floor Analysis and Beyond 
the MACT Floor Analysis for Subcategory of Existing Eastern 
Bituminous Coal Refuse-Fired EGUs Under Consideration, available in 
Docket ID No. EPA-HQ-OAR-2018-0794.
    \24\ At the time of the 2019 Proposal's analysis, SO2 
data through June 2018 were available. Data that have become 
available only after the 2019 Proposal is not a necessary basis of 
our discussion of that Proposal or the EPA's final action here, but 
it generally corroborates the basis already available and noticed to 
the public in February 2019. New data that have since become 
available to the EPA are discussed later in this section of this 
preamble.

           Table 4--MACT Floor and Beyond-the-Floor Results for Potential EBCR-Fired EGUs Subcategory
----------------------------------------------------------------------------------------------------------------
           Subcategory                 Parameter                    HCl                          SO2
----------------------------------------------------------------------------------------------------------------
Existing Eastern Bituminous Coal  Number in MACT       5...........................  5
 Refuse-Fired EGUs.                Floor.
                                  99% UPL \a\ of Top   6.0E-2 lb/MMBtu.............  1.0 lb/MMBtu
                                   5 (i.e., MACT       6.0E-1 lb/MWh...............  15 lb/MWh
                                   floor).
                                  Beyond-the-floor     4.0E-2 lb/MMBtu.............  6.0E-1 lb/MMBtu
                                   Standard.           4.0E-1 lb/MWh...............  9.0 lb/MWh
----------------------------------------------------------------------------------------------------------------
\a\ Upper prediction limit.

    Immediately below and in the response to comments document, we 
discuss in more detail the basis for the acid gas HAP emission 
standards that are applicable to the new subcategory and address the 
significant comments on the standards for the new subcategory.
    In response to the 2019 Proposal's solicitation of comment, the EPA 
received comments both supporting and opposing its analysis to 
determine the numerical acid gas emission standards for a subcategory 
of existing EBCR-fired EGUs. Several commenters agreed with the 
methodology that the EPA used to determine the MACT floor and beyond-
the-floor levels of control for emissions of SO2 and HCl. 
Commenters further stated that an SO2 limit of 0.6 lb/MMBtu, 
as discussed in the 2019 Proposal, is reasonable, technologically and 
economically defensible, and would allow facilities to continue 
providing multimedia environmental benefits from coal refuse 
reclamation and remediation of mining-affected lands. Other commenters 
disagreed with the EPA's analyses of the MACT floor and beyond-the-
floor levels of control and the resulting emission limits presented in 
the 2019 Proposal. Specifically, commenters disagreed with the data 
used in the analyses, claiming that it is not representative of the 
emissions reductions achieved in practice by the best-performing 
sources because it excludes time periods when controls were installed. 
In addition, commenters stated that the beyond-the-floor analysis fails 
to recognize that each plant in the subcategory already has acid gas 
controls sufficient to meet the current standard and, instead, assumes 
that such controls are infeasible. Further, commenters stated that the 
only relevant cost for purposes of any beyond-the-floor standard is the 
cost of operating (rather than installing) the control.
    The EPA disagrees with those comments opposing the data used in the 
MACT floor and beyond-the-floor analyses and the resulting emission 
limits. The MACT floor analyses for HCl and SO2 for the 
subcategory of EBCR-fired EGUs are reasonably based on the same 2010 
ICR dataset and methodology used to determine MACT floor emission 
values for pollutants regulated under the 2012 MATS final rule. HCl and 
SO2 emissions data for the EBCR-fired EGUs that were 
operating at the time of the 2012 MATS final rule were used to 
calculate separate existing source MACT floors for HCl in lb/MMBtu and 
lb/MWh and SO2 in lb/MMBtu and lb/MWh. Thus, the MACT floor 
analysis and resulting floor values are consistent with how MACT floors 
for other HAP emissions standards were calculated and are 
representative of the HCl and SO2 emissions reductions 
achieved in practice by the best-performing EBCR-fired EGUs at that 
time, irrespective of the means that the reductions were achieved.
    The beyond-the-floor analysis and resulting beyond-the-floor 
emission limit for SO2 lb/MMBtu are reasonably based on the 
extensive data available in the EPA's ECMPS for each currently 
operating EBCR-fired EGU. As described in the 2019 Proposal, an 
SO2 emission limit of 0.6 lb/MMBtu is a limit that the 
currently operating EBCR-fired EGUs have demonstrated an ability to 
achieve based on their monthly emissions data for January 2015 through 
June 2018. Any means being used to control acid gases during that time 
period would be reflected in the average SO2 lb/MMBtu 
emission rate for those EBCR-fired EGUs. Thus, the EPA's analysis does 
not exclude time periods when controls were installed. We note, 
however, that we are unaware of any EBCR-fired EGUs that have installed 
any downstream acid gas controls in addition to limestone injection 
into the FBC in response to the 2012 MATS rule. Further, the EPA has 
confirmed that extending the time horizon through March 2019 to include 
emissions data that have become available since the analysis for the 
2019 Proposal would not result in changes to average SO2 lb/
MMBtu emission rates for the currently operating EBCR-fired EGUs nor to 
the SO2 emission limit of 0.6 lb/MMBtu that, on average, 
those EGUs have achieved for that time period.\25\
---------------------------------------------------------------------------

    \25\ Including EBCR-fired EGUs' SO2 emissions data 
for the time period of July 2018 through March 2019 results in minor 
changes to average SO2 emissions values for some EBCR-
fired EGUs but does not result in a change to the beyond-the-floor 
emission limit for SO2 lb/MMBtu. Nevertheless, the more 
recent SO2 data is included in an addendum to the 2019 
Proposal's analysis, titled NESHAP for Coal- and Oil-Fired EGUs: 
Addendum to MACT Floor Analysis and Beyond the MACT Floor Analysis 
for Subcategory of Existing Eastern Bituminous Coal Refuse-Fired 
EGUs Under Consideration, available in Docket ID No. EPA-HQ-OAR-
2018-0794.
---------------------------------------------------------------------------

    Contrary to some comments, the beyond-the-floor analysis does 
recognize that each EBCR-fired EGU in the subcategory has controls to 
address acid gas emissions and, as explained earlier, average 
SO2 lb/MMBtu emission rates reflect those controls. In 
addition, the 2019 Proposal, as well as section

[[Page 20847]]

III.A of this preamble, point out that all coal refuse fuels are fired 
in FBC that use limestone injection to minimize SO2 
emissions and to increase heat transfer efficiency. As discussed in 
section III.A of this preamble, commenters have pointed out, however, 
that there are limitations on the ability of existing EBCR-fired EGUs 
to control acid gas emissions to the level of the 2012 final MATS acid 
gas standard by increasing the amount of limestone injected. As such, 
the EPA disagrees with comments claiming that the current controls are 
sufficient to meet the 2012 final MATS acid gas standard and that, 
therefore, the only relevant cost for purposes of any beyond-the-floor 
standard is the cost of operating (rather than installing) the control. 
As also discussed in section III.A of this preamble, commenters have 
pointed out feasibility issues associated with installation and 
operation of various downstream acid gas control technologies in order 
to meet the 2012 final MATS acid gas standard. For those same reasons, 
the EPA determined that downstream acid gas control technologies such 
as scrubbers (either wet FGD scrubbers or SDA) or DSI systems are not 
beyond-the-floor options for acid gas HAP emissions from the 
subcategory of existing EBCR-fired EGUs.\26\
---------------------------------------------------------------------------

    \26\ See, also, the memorandum titled NESHAP for Coal- and Oil-
Fired EGUs: Addendum to MACT Floor Analysis and Beyond the MACT 
Floor Analysis for Subcategory of Existing Eastern Bituminous Coal 
Refuse-Fired EGUs Under Consideration, available in Docket ID No. 
EPA-HQ-OAR-2018-0794.
---------------------------------------------------------------------------

    Based on a review of the public comments and other available 
information, the EPA is finalizing HCl and SO2 emission 
limits reflecting beyond-the-floor level of control using the 
methodology described in the 2019 Proposal and earlier in this section 
of the preamble. Specifically, this action establishes the following 
emission limits for the new subcategory of existing EBCR-fired EGUs:

HCl: 4.0E-2 lb/MMBtu or 4.0E-1 lb/MWh
SO2: \27\ 6.0E-1 lb/MMBtu or 9.0 lb/MWh
---------------------------------------------------------------------------

    \27\ As is the requirement for all coal-fired EGUs subject to 
MATS, the alternate SO2 limit may be used if the EGU has 
some form of FGD system and SO2 CEMS and both are 
installed and operated at all times. As specified in 40 CFR 
63.10000(c)(1)(v) of the 2012 MATS final rule, limestone injection 
to an FBC unit is an ``FGD system'' that would allow the EBCR-fired 
EGUs to use the alternative SO2 standard.

    The SO2 lb/MMBtu emissions limit is a limit that, on 
average, the currently operating EBCR-fired EGUs have achieved based on 
their monthly emissions data for January 2015 through June 2018.\28\ 
Because the EPA does not have such HCl emissions data or SO2 
lb/MWh emissions data, beyond-the-floor standards for SO2 in 
lb/MWh and for HCl in lb/MMBtu and lb/MWh are based on the percentage 
reduction in the SO2 lb/MMBtu emissions rate between the 
MACT floor value and the beyond-the-floor value.
---------------------------------------------------------------------------

    \28\ As previously explained in this preamble, at the time of 
the 2019 Proposal's analysis, SO2 data through June 2018 
were available. Inclusion of data that has become available only 
after the 2019 Proposal does not result in a change to the beyond-
the-floor emission limit for SO2 lb/MMBtu. See the 
memorandum titled NESHAP for Coal- and Oil-Fired EGUs: Addendum to 
MACT Floor Analysis and Beyond the MACT Floor Analysis for 
Subcategory of Existing Eastern Bituminous Coal Refuse-Fired EGUs 
Under Consideration, available in Docket ID No. EPA-HQ-OAR-2018-
0794.
---------------------------------------------------------------------------

IV. Summary of Cost, Environmental, and Economic Impacts and Additional 
Analyses Conducted

A. What are the affected sources?

    Affected sources are EGUs that are in the unit designed for eastern 
bituminous coal refuse (EBCR) subcategory, as defined under this final 
action. Based on available information, there are six currently 
operating EBCR-fired EGUs that are in the newly established subcategory 
and subject to the newly established acid gas HAP emission standards. 
The six EGUs, located at three facilities in Pennsylvania and one 
facility in West Virginia, are listed in Table 2 of this preamble.

B. What are the air quality impacts?

    Absent the subcategory finalized in this action, many affected 
EBCR-fired EGUs would likely discontinue operations. Although the new 
emission standards will allow higher acid gas HAP and SO2 
emissions from these facilities compared to the emission standards in 
the original 2012 MATS, emissions of other HAP will not change under 
this action. These higher allowable emissions may, however, be 
partially offset. In the absence of this rule, closure of the units 
would likely result in reduced remediation of abandoned mine lands 
(AMLs) and potentially increase the risk and impact of emissions from 
refuse piles. Refuse piles at AMLs are prone to spontaneous internal 
combustion (smoldering) which emits uncontrolled air pollutants 
including acid gases and other HAP, and with less remediation, the 
potential for greater emissions from smoldering increases. More 
detailed analysis of potential air impacts of this rule is presented in 
a docketed memorandum.\29\
---------------------------------------------------------------------------

    \29\ See the memorandum titled Analysis of Potential Costs and 
Benefits for the National Emission Standards for Hazardous Air 
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating 
Units--Subcategory of Certain Existing Electric Utility Steam 
Generating Units Firing Eastern Bituminous Coal Refuse for Emissions 
of Acid Gas Hazardous Air Pollutants, available in Docket ID No. 
EPA-HQ-OAR-2018-0794
---------------------------------------------------------------------------

C. What are the compliance cost impacts?

    Relative to a baseline in which the subcategory is not finalized 
and the existing 2012 MATS acid gas HAP emissions limits are enforced, 
the new subcategory could reduce costs by eliminating the need for 
investment in additional compliance measures which have not yet been 
made by affected units. The magnitude of potential cost reductions is 
discussed in a docketed memorandum.\30\
---------------------------------------------------------------------------

    \30\ Ibid.
---------------------------------------------------------------------------

D. What are the economic impacts?

    The impact of the newly finalized subcategory of EBCR-fired EGUs 
for emissions of acid gas HAP on the broader electricity sector is 
likely to be minor due to the relatively small size of these 
facilities. Additionally, the risk of the affected EBCR-fired EGUs 
closing because of challenges in meeting MATS acid gas HAP limits is 
reduced by the new subcategory. As a result, the coal refuse 
reclamation services the units provide are more likely to be sustained 
in the future, potentially offsetting reclamation costs that may be 
otherwise incurred by the states of Pennsylvania and West Virginia. 
Additionally, because of the reduced risk of closure, the acid gas HAP 
subcategory finalized in this action could prevent labor market 
transitions for individuals who operate and perform support functions 
for these facilities. However, it may limit labor market opportunities 
that could result from AML reclamation by other means.

E. What are the forgone benefits?

    Absent the subcategory finalized in this action, affected EBCR-
fired EGUs would likely either discontinue operations or perform 
compliance measures to comply with the previous MATS acid gas HAP 
limits, which would have the effect of reducing acid gas HAP emissions. 
The newly finalized subcategory will likely increase emissions of 
SO2 relative to a baseline in which the subcategory is not 
finalized; this in turn would form fine PM (PM2.5) 
concentrations in the atmosphere and potentially adversely affect human 
health. The magnitude of those forgone co-benefits depends on the 
magnitude of the air quality impacts described earlier. Notably, most 
counties in Pennsylvania and bordering

[[Page 20848]]

states attain the current PM2.5 National Ambient Air Quality 
Standards (NAAQS), set at a level requisite to protect public health 
with an adequate margin of safety. The magnitude of potential forgone 
benefits is discussed in a docketed memorandum.\31\
---------------------------------------------------------------------------

    \31\ Ibid.
---------------------------------------------------------------------------

    In contrast, if plants continue to operate when they otherwise 
would not have absent this action, the continued remediation of AMLs 
could provide water quality co-benefits through reductions in toxic 
metal leaching and acid mine drainage. As noted earlier, removal of 
coal refuse piles reduces surface and groundwater pollution from acidic 
drainage and reduces uncontrolled emissions of air pollutants that are 
released from self-ignited internal smoldering of the coal refuse 
piles. In addition, commenters pointed out that the alkaline ash 
produced by EBCR-fired EGUs is used to reclaim mining-affected lands by 
returning them to a productive use.
    Remediation of AMLs through the use of waste coal is supported by 
the state of Pennsylvania through policies such as tax credits and 
treatment of these units as renewable for purposes of the state's 
renewable portfolio standard. If these waste coal units are no longer 
able to operate, the state will need to find alternative means to 
remediate these sites leading to, at best, a delay in these benefits, 
if not a loss of these benefits altogether. These benefits are 
discussed qualitatively in greater detail in the docketed memorandum.
    As noted earlier, while the EPA cannot predict with certainty what 
the industry response would be absent the establishment of a new 
subcategory, industry commenters have suggested that some--and maybe 
all--of the affected sources would shut down.\32\ If that is the case, 
then the establishment of this new subcategory will allow those units 
to continue to achieve both of their purposes while also maintaining 
emissions of acid gas HAP at levels similar to current emissions 
levels.
---------------------------------------------------------------------------

    \32\ See EPA Docket ID Item Nos. EPA-HQ-OAR-2018-0794-1125 and 
EPA-HQ-OAR-2018-0794-1154.
---------------------------------------------------------------------------

    While the EPA cannot predict with certainty what the industry 
response would be in the absence of a new subcategory, commenters' 
claim that the units would shut down is plausible. Coal-fired power 
plants are currently facing tremendous competitive pressures. As a 
result, coal's share of total U.S. electricity generation has been 
declining for over a decade, while generation from natural gas and 
renewables has increased significantly. A large number of coal units--
especially smaller ones like the EBCR-fired EGUs--have retired since 
2010. Indeed, as mentioned earlier, four of the ten units that were 
identified as affected by this action in the 2019 Proposal have now 
either retired or announced plans to convert to natural gas.

V. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is an economically significant regulatory action that 
was submitted to the Office of Management and Budget (OMB) for review. 
Any changes made in response to OMB recommendations have been 
documented in the docket. The EPA has conducted an analysis of all 
reasonably anticipated costs and benefits arising out of this rule, 
including those arising out of co-benefits pursuant to Executive Orders 
12866 and 13563. That analysis can be found in a separate memorandum 
titled Analysis of Potential Costs and Benefits for the National 
Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired 
Electric Utility Steam Generating Units--Subcategory of Certain 
Existing Electric Utility Steam Generating Units Firing Eastern 
Bituminous Coal Refuse for Emissions of Acid Gas Hazardous Air 
Pollutants, that is available in the docket.

B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs

    This action is considered an Executive Order 13771 deregulatory 
action. This final rule provides meaningful burden reduction by 
revising the acid gas HAP emission standards for a new subcategory of 
certain existing EGUs that are currently subject to MATS and does not 
impose any additional regulatory requirements on the affected electric 
utility industry.

C. Paperwork Reduction Act (PRA)

    This action does not impose any new information collection burden 
under the PRA. OMB has previously approved the information collection 
activities contained in the existing regulations and has assigned OMB 
control number 2060-0567. This action does not impose an information 
collection burden because the regulatory changes resulting from this 
action do not affect the currently approved information collection 
requirements. Specifically, this action establishes acid gas HAP 
emission standards for a new subcategory of certain existing EGUs that 
are currently subject to MATS and the new emission standards do not 
result in any changes to the recordkeeping or reporting requirements 
that those impacted EGUs are currently subject to.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. In 
making this determination, the impact of concern is any significant 
adverse economic impact on small entities. An agency may certify that a 
rule will not have a significant economic impact on a substantial 
number of small entities if the rule relieves regulatory burden, has no 
net burden, or otherwise has a positive economic effect on the small 
entities subject to the rule. This is a deregulatory action, and the 
burden on all entities affected by this final rule, including small 
entities, is reduced compared to the 2012 MATS.

E. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. The action imposes 
no enforceable duty on any state, local or tribal governments or the 
private sector.

F. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

G. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. It will neither impose substantial direct 
compliance costs on tribal governments, nor preempt Tribal law. 
Specifically, this action establishes acid gas HAP emission standards 
for a new subcategory of certain existing EGUs currently subject to 
MATS and located in Pennsylvania and West Virginia, states without any 
federally recognized tribal entities. Thus,

[[Page 20849]]

Executive Order 13175 does not apply to this action.
    Consistent with the EPA Policy on Consultation and Coordination 
with Indian Tribes, the EPA consulted with tribal officials during the 
development of this action. The EPA held consultations with the Blue 
Lake Rancheria and the Fond du Lac Band of Lake Superior Chippewa on 
April 2, 2019, and April 3, 2019, respectively. Neither tribe provided 
comments regarding the 2019 Proposal's solicitation of comment on 
establishing a subcategory of certain existing EGUs firing EBCR for 
acid gas HAP emissions.

H. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because the EPA 
does not believe the environmental health risks or safety risks 
addressed by this action present a disproportionate risk to children. 
While children may experience forgone benefits as a result of this 
action, the potential forgone emission reductions (and related 
benefits) from the final amendments are small compared to the overall 
emission reductions (and related benefits) from the 2012 MATS.
    Furthermore, this action does not affect the level of public health 
and environmental protection already being provided by existing NAAQS 
and other mechanisms in the CAA. This action does not affect applicable 
local, state, or federal permitting or air quality management programs 
that will continue to address areas with degraded air quality and 
maintain the air quality in areas meeting current standards. Areas that 
need to reduce criteria air pollution to meet the NAAQS will still need 
to rely on control strategies to reduce emissions. To the extent that 
states use other mechanisms in order to comply with the NAAQS, and 
still achieve the criteria pollution reductions that would have 
otherwise occurred, this action will not have a disproportionate 
adverse effect on children's health.

I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. Further, the EPA concludes that this 
action is not likely to have any adverse energy effects because it 
establishes acid gas HAP emission standards for a new subcategory of 
certain existing EGUs that are currently subject to MATS and does not 
impose any additional regulatory requirements on the affected electric 
utility industry.

J. National Technology Transfer and Advancement Act (NTTAA)

    This action does not involve technical standards.

K. Executive Order 12898: Federal Actions to Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action does not have disproportionately 
high and adverse human health or environmental effects on minority 
populations, low-income populations, and/or indigenous peoples, as 
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). 
While these communities may experience forgone benefits as a result of 
this action, the potential forgone emission reductions (and related 
benefits) from the final action are small compared to the overall 
emission reductions (and related benefits) from the 2012 MATS.
    Moreover, this action does not affect the level of public health 
and environmental protection already being provided by existing NAAQS, 
including ozone and PM2.5, and other mechanisms in the CAA. 
This action does not affect applicable local, state, or federal 
permitting or air quality management programs that will continue to 
address areas with degraded air quality and maintain the air quality in 
areas meeting current standards. Areas that need to reduce criteria air 
pollution to meet the NAAQS will still need to rely on control 
strategies to reduce emissions.

L. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. The CRA allows the issuing agency to make a rule 
effective sooner than otherwise provided by the CRA if the agency makes 
a good cause finding under the provisions of 5 U.S.C. 808(2). The EPA 
finds that there is good cause under the provisions of 5 U.S.C. 808(2) 
to make this final rule effective without full, prior Congressional 
review under 5 U.S.C. 801 and to make the rule effective on April 15, 
2020. The EPA finds that it is unnecessary to delay the date this rule 
could be effective because the Agency has determined that the owners or 
operators of affected MATS sources do not need time to adjust to this 
final action. This final action establishes a subcategory of certain 
existing EGUs firing EBCR and acid gas HAP emission standards 
applicable only to the new subcategory. Sources in the new subcategory 
will be subject to an SO2 emissions limit that, on average, 
the currently operating six EBCR-fired EGUs have demonstrated an 
ability to achieve but, otherwise, will not be subject to any new 
regulatory requirements.\33\
---------------------------------------------------------------------------

    \33\ Affected sources may report emissions of either 
SO2 or HCl. Most MATS-affected EGUs report emissions of 
SO2 because they already report SO2 emissions 
under the EPA's Acid Rain Program.
---------------------------------------------------------------------------

    The EPA also finds that it is impracticable to delay the effective 
date of this rule. Three of the four facilities with EBCR-fired EGUs in 
the new subcategory are subject to EPA-issued Administrative Compliance 
Orders that provide interim SO2 emission limits that 
terminate on April 15, 2020. Those facilities have asserted that they 
cannot meet the 2012 final MATS HCl emission standard, or the 2012 
final MATS SO2 acid gas HAP surrogate emission standard, 
while burning the coal refuse fuel for which their facilities were 
designed. By 11:59 p.m. on April 15, 2020, EBCR-fired EGUs at those 
facilities must achieve full compliance with MATS. Absent this final 
action's acid gas HAP emission standards for the new subcategory being 
effective by that date, EGUs at those three facilities would be subject 
to the 2012 final MATS acid gas HAP emission standards that they are 
not currently in compliance with, and, thus, in violation of their 
Orders. According to the facilities, if subject to the 2012 acid gas 
HAP emission standards, they would no longer be in a position to 
continue operating their EBCR-fired EGUs and, thus, provide the 
environmental benefits associated with removal of coal refuse piles and 
reclamation and remediation of mining-affected lands.
    Accordingly, the EPA finds it would be unnecessary and 
impracticable to delay the effective date of this action and that there 
is good cause to dispense with the opportunity for a 60-day period of 
prior Congressional review and to publish this final rule with an 
effective date of April 15, 2020.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedures, 
Air pollution control, Hazardous substances, Intergovernmental 
relations, Reporting and recordkeeping requirements.

Andrew Wheeler,
Administrator.

    For the reasons set forth in the preamble, the Environmental 
Protection Agency amends 40 CFR part 63 as follows:

[[Page 20850]]

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

0
1. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart UUUUU--National Emission Standards for Hazardous Air 
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating 
Units

0
2. Section 63.9982 is amended by revising paragraph (d) to read as 
follows:


Sec.  63.9982  What is the affected source of this subpart?

* * * * *
    (d) An EGU is existing if it is not new or reconstructed. An 
existing electric steam generating unit that meets the applicability 
requirements after April 16, 2012, due to a change in process (e.g., 
fuel or utilization) is considered to be an existing source under this 
subpart.

0
3. Section 63.9984 is amended by revising paragraphs (b) and (f) and 
adding paragraph (g) to read as follows:


Sec.  63.9984  When do I have to comply with this subpart?

* * * * *
    (b) If you have an existing EGU, you must comply with this subpart 
no later than April 16, 2015, except as provided in paragraph (g) of 
this section.
* * * * *
    (f) You must demonstrate that compliance has been achieved, by 
conducting the required performance tests and other activities, no 
later than 180 days after the applicable date in paragraph (a), (b), 
(c), (d), (e), or (g) of this section.
    (g) If you own or operate an EGU that is in the Unit designed for 
eastern bituminous coal refuse (EBCR) subcategory as defined in Sec.  
63.10042, you must comply with the applicable hydrogen chloride (HCl) 
or sulfur dioxide (SO2) requirements of this subpart no 
later than April 15, 2020.

0
4. Section 63.9990 is amended by revising paragraph (a) to read as 
follows:


Sec.  63.9990  What are the subcategories of EGUs?

    (a) Coal-fired EGUs are subcategorized as defined in paragraphs 
(a)(1) through (3) of this section and as defined in Sec.  63.10042.
    (1) EGUs designed for coal with a heating value greater than or 
equal to 8,300 Btu/lb,
    (2) EGUs designed for low rank virgin coal, and
    (3) EGUs designed for EBCR.
* * * * *

0
5. Section 63.10042 is amended by adding definitions for ``Eastern 
bituminous coal refuse (EBCR),'' ``Net summer capacity,'' and ``Unit 
designed for eastern bituminous coal refuse (EBCR) subcategory'' in 
alphabetical order to read as follows:


Sec.  63.10042  What definitions apply to this subpart?

* * * * *
    Eastern bituminous coal refuse (EBCR) means coal refuse generated 
from the mining of bituminous coal in Pennsylvania and West Virginia.
* * * * *
    Net summer capacity means the maximum output, commonly expressed in 
megawatts (MW), that generating equipment can supply to system load, as 
demonstrated by a multi-hour test, at the time of summer peak demand 
(period of June 1 through September 30.) This output reflects a 
reduction in capacity due to electricity use for station service or 
auxiliaries.
* * * * *
    Unit designed for eastern bituminous coal refuse (EBCR) subcategory 
means any existing (i.e., construction was commenced on or before May 
3, 2011) coal-fired EGU with a net summer capacity of no greater than 
150 MW that is designed to burn and that is burning 75 percent or more 
(by heat input) eastern bituminous coal refuse on a 12-month rolling 
average basis.
* * * * *

0
6. Table 2 to Subpart UUUUU of Part 63 is revised to read as follows:

Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs

    As stated in Sec.  63.9991, you must comply with the following 
applicable emission limits: \1\

----------------------------------------------------------------------------------------------------------------
                                                                                               Using these
                                                                                             requirements, as
                                                                   You must meet the        appropriate (e.g.,
                                                                   following emission       specified sampling
 If your EGU is in this subcategory .     For the following         limits and work         volume or test run
                 . .                       pollutants . . .      practice standards . .       duration) and
                                                                           .               limitations with the
                                                                                         test methods in Table 5
                                                                                          to this Subpart . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank        a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 virgin coal.                           particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.

[[Page 20851]]

 
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A at
                                        (HCl).                   2 lb/MWh.                appendix A-8 to part
                                                                                          60 of this chapter,
                                                                                          collect a minimum of
                                                                                          0.75 dscm per run; for
                                                                                          Method 26, collect a
                                                                                          minimum of 120 liters
                                                                                          per run. For ASTM
                                                                                          D6348-03 3 or Method
                                                                                          320 at appendix A to
                                                                                          part 63 of this
                                                                                          chapter, sample for a
                                                                                          minimum of 1 hour.
                                       OR.....................  .......................  .......................
                                       Sulfur dioxide (SO2) 4.  2.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  1.2E0 lb/TBtu or 1.3E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          at appendix A-8 to
                                                                                          part 60 of this
                                                                                          chapter run or Hg CEMS
                                                                                          or sorbent trap
                                                                                          monitoring system
                                                                                          only.
                                                                OR                       .......................
                                                                1.0E0 lb/TBtu or 1.1E-2  LEE Testing for 90 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          run or Hg CEMS or
                                                                                          sorbent trap
                                                                                          monitoring system
                                                                                          only.
2. Coal-fired unit low rank virgin     a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 coal.                                  particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                          per run; for Method 26
                                                                                          at appendix A-8 to
                                                                                          part 60 of this
                                                                                          chapter, collect a
                                                                                          minimum of 120 liters
                                                                                          per run. For ASTM
                                                                                          D6348-03 3 or Method
                                                                                          320, sample for a
                                                                                          minimum of 1 hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 4.  2.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 1.5E0 lb/MWh.
                                       c. Mercury (Hg)........  4.0E0 lb/TBtu or 4.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          run or Hg CEMS or
                                                                                          sorbent trap
                                                                                          monitoring system
                                                                                          only.

[[Page 20852]]

 
3. IGCC unit.........................  a. Filterable            4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
                                        particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  1.4E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Arsenic (As)...........  1.5E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  1.0E-1 lb/TBtu or 1.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  1.5E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.9E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Lead (Pb)..............  1.9E+2 lb/TBtu or 1.8E0  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.5E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  6.5E0 lb/TBtu or 7.0E-2  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  2.2E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       b. Hydrogen chloride     5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HCl).                   3 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                          For ASTM D6348-03 3 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       c. Mercury (Hg)........  2.5E0 lb/TBtu or 3.0E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          run or Hg CEMS or
                                                                                          sorbent trap
                                                                                          monitoring system
                                                                                          only.
4. Liquid oil-fired unit--continental  a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 (excluding limited-use liquid oil-     particulate matter       1 lb/MWh 2.              dscm per run.
 fired subcategory units).              (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 1
                                                                                          dscm per run.
                                       Antimony (Sb)..........  1.3E+1 lb/TBtu or 2.0E-  .......................
                                                                 1 lb/GWh.
                                       Arsenic (As)...........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  5.5E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  2.1E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Lead (Pb)..............  8.1E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.2E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  1.1E+2 lb/TBtu or 1.1E0  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  3.3E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Mercury (Hg)...........  2.0E-1 lb/TBtu or 2.0E-  For Method 30B sample
                                                                 3 lb/GWh.                volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be < 1 2 the
                                                                                          standard.

[[Page 20853]]

 
                                       b. Hydrogen chloride     2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                          For ASTM D6348-03 3 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       c. Hydrogen fluoride     4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
                                        (HF).                    3 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                          For ASTM D6348-03 3 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
5. Liquid oil-fired unit--non-         a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 continental (excluding limited-use     particulate matter       1 lb/MWh 2.              dscm per run.
 liquid oil-fired subcategory units).   (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
                                                                 3 lb/MWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                          dscm per run.
                                       Antimony (Sb)..........  2.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Arsenic (As)...........  4.3E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  6.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  3.1E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Cobalt (Co)............  1.1E+2 lb/TBtu or 1.4E0  .......................
                                                                 lb/GWh.
                                       Lead (Pb)..............  4.9E0 lb/TBtu or 8.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  2.0E+1 lb/TBtu or 3.0E-  .......................
                                                                 1 lb/GWh.
                                       Nickel (Ni)............  4.7E+2 lb/TBtu or 4.1E0  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  9.8E0 lb/TBtu or 2.0E-1  .......................
                                                                 lb/GWh.
                                       Mercury (Hg)...........  4.0E-2 lb/TBtu or 4.0E-  For Method 30B sample
                                                                 4 lb/GWh.                volume determination
                                                                                          (Section 8.2.4), the
                                                                                          estimated Hg
                                                                                          concentration should
                                                                                          nominally be < 1 2 the
                                                                                          standard.
                                       b. Hydrogen chloride     2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
                                        (HCl).                   3 lb/MWh.                a minimum of 1 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                          For ASTM D6348-03 3 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 2 hours.
                                       c. Hydrogen fluoride     6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
                                        (HF).                    4 lb/MWh.                a minimum of 3 dscm
                                                                                          per run. For ASTM
                                                                                          D6348-03 3 or Method
                                                                                          320, sample for a
                                                                                          minimum of 2 hours.
6. Solid oil-derived fuel-fired unit.  a. Filterable            8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
                                        particulate matter       2 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 7.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  3.0E-1 lb/TBtu or 5.0E-  .......................
                                                                 3 lb/GWh.
                                       Beryllium (Be).........  6.0E-2 lb/TBtu or 5.0E-  .......................
                                                                 4 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 4.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  8.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 2 lb/GWh.
                                       Cobalt (Co)............  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.

[[Page 20854]]

 
                                       Lead (Pb)..............  8.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 2 lb/GWh.
                                       Manganese (Mn).........  2.3E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  9.0E0 lb/TBtu or 2.0E-1  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  1.2E0 lb/Tbtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
                                        (HCl).                   2 lb/MWh.                a minimum of 0.75 dscm
                                                                                          per run; for Method
                                                                                          26, collect a minimum
                                                                                          of 120 liters per run.
                                                                                          For ASTM D6348-03 3 or
                                                                                          Method 320, sample for
                                                                                          a minimum of 1 hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 4.  3.0E-1 lb/MMBtu or       SO2 CEMS.
                                                                 2.0E0 lb/MWh.
                                       c. Mercury (Hg)........  2.0E-1 lb/TBtu or 2.0E-  LEE Testing for 30 days
                                                                 3 lb/GWh.                with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          run or Hg CEMS or
                                                                                          sorbent trap
                                                                                          monitoring system
                                                                                          only.
7. Eastern Bituminous Coal Refuse      a. Filterable            3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
 (EBCR)-fired unit.                     particulate matter       1 lb/MWh 2.              dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
                                                                 1 lb/GWh.                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                          dscm per run.
                                       Antimony (Sb)..........  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Arsenic (As)...........  1.1E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Beryllium (Be).........  2.0E-1 lb/TBtu or 2.0E-  .......................
                                                                 3 lb/GWh.
                                       Cadmium (Cd)...........  3.0E-1 lb/TBtu or 3.0E-  .......................
                                                                 3 lb/GWh.
                                       Chromium (Cr)..........  2.8E0 lb/TBtu or 3.0E-2  .......................
                                                                 lb/GWh.
                                       Cobalt (Co)............  8.0E-1 lb/TBtu or 8.0E-  .......................
                                                                 3 lb/GWh.
                                       Lead (Pb)..............  1.2E0 lb/TBtu or 2.0E-2  .......................
                                                                 lb/GWh.
                                       Manganese (Mn).........  4.0E0 lb/TBtu or 5.0E-2  .......................
                                                                 lb/GWh.
                                       Nickel (Ni)............  3.5E0 lb/TBtu or 4.0E-2  .......................
                                                                 lb/GWh.
                                       Selenium (Se)..........  5.0E0 lb/TBtu or 6.0E-2  .......................
                                                                 lb/GWh.
                                       b. Hydrogen chloride     4.0E-2 lb/MMBtu or.....  For Method 26A at
                                        (HCl).                  4.0E-1 lb/MWh..........   appendix A-8 to part
                                                                                          60 of this chapter,
                                                                                          collect a minimum of
                                                                                          0.75 dscm per run; for
                                                                                          Method 26, collect a
                                                                                          minimum of 120 liters
                                                                                          per run. For ASTM
                                                                                          D6348-03 3 or Method
                                                                                          320 at appendix A to
                                                                                          part 63 of this
                                                                                          chapter, sample for a
                                                                                          minimum of 1 hour.
                                       OR                                                .......................
                                       Sulfur dioxide (SO2) 4.  6E-1 lb/MMBtu or 9E0 lb/ SO2 CEMS.
                                                                 MWh.
                                       c. Mercury (Hg)........  1.2E0 lb/TBtu or 1.3E-2  LEE Testing for 30 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          at appendix A-8 to
                                                                                          part 60 of this
                                                                                          chapter run or Hg CEMS
                                                                                          or sorbent trap
                                                                                          monitoring system
                                                                                          only.
                                                                OR                       .......................

[[Page 20855]]

 
                                                                1.0E0 lb/TBtu or 1.1E-2  LEE Testing for 90 days
                                                                 lb/GWh.                  with a sampling period
                                                                                          consistent with that
                                                                                          given in section 5.2.1
                                                                                          of appendix A to this
                                                                                          subpart per Method 30B
                                                                                          run or Hg CEMS or
                                                                                          sorbent trap
                                                                                          monitoring system
                                                                                          only.
----------------------------------------------------------------------------------------------------------------
\1\ For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required
  minimum sampling volume must be increased nominally by a factor of 2.
\2\ Gross output.
\3\ Incorporated by reference, see Sec.   63.14.
\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
  installed.

[FR Doc. 2020-07878 Filed 4-14-20; 8:45 am]
BILLING CODE 6560-50-P

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