National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Amendments, 52198-52236 [2020-15121]

Download as PDF 52198 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 63 [EPA–HQ–OAR–2002–0058; FRL–10010–81– OAR] RIN 2060–AU20 National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Amendments Environmental Protection Agency (EPA). ACTION: Proposed rule. AGENCY: On January 31, 2013, the U.S. Environmental Protection Agency (EPA) finalized amendments to the national emission standards (NESHAP) for the control of hazardous air pollutants (HAP) at major sources from new and existing industrial, commercial, and institutional (ICI) boilers and process heaters. Subsequently, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), in a decision issued in July 2016, remanded several of the emission standards to the EPA based on the court’s review of the EPA’s approach to setting those standards. In response to these remands, this action proposes to amend several numeric emission limits for new and existing boilers and process heaters consistent with the court’s opinion and set compliance dates for these new emission limits. The court also remanded for further explanation the Agency’s use of carbon monoxide (CO) as a surrogate for organic HAP and, in a subsequent decision in March 2018, remanded for further explanation the Agency’s use of a CO threshold to represent the application of the maximum achievable control technology (MACT) for organic HAP. The proposed changes to the emissions limits will protect air quality and promote public health by reducing emissions of the HAP listed in the Clean Air Act (CAA). This action also addresses the two issues remanded to the EPA for further explanation. We are also proposing several technical clarifications and corrections. DATES: Comments. Comments must be received on or before October 23, 2020. Under the Paperwork Reduction Act (PRA), comments on the information collection provisions are best assured of consideration if the Office of Management and Budget (OMB) receives a copy of your comments on or before September 23, 2020. jbell on DSKJLSW7X2PROD with PROPOSALS2 SUMMARY: VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 Public hearing. If anyone contacts us requesting a public hearing on or before August 31, 2020, we will hold a virtual public hearing. See SUPPLEMENTARY INFORMATION for information on requesting and registering for a public hearing. ADDRESSES: You may send comments, identified by Docket ID No. EPA–HQ– OAR–2002–0058, by any of the following methods: • Federal eRulemaking Portal: https://www.regulations.gov/ (our preferred method). Follow the online instructions for submitting comments. • Email: a-and-r-docket@epa.gov. Include Docket ID No. EPA–HQ–OAR– 2002–0058 in the subject line of the message. Instructions: All submissions received must include the Docket ID No. for this rulemaking. Comments received may be posted without change to https:// www.regulations.gov/, including any personal information provided. For detailed instructions on sending comments and additional information on the rulemaking process, see the SUPPLEMENTARY INFORMATION section of this document. Out of an abundance of caution for members of the public and our staff, the EPA Docket Center and Reading Room was closed to public visitors on March 31, 2020, to reduce the risk of transmitting COVID–19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https:// www.regulations.gov/ or email, as there is a temporary suspension of mail delivery to the EPA, and no hand deliveries are currently accepted. For further information on EPA Docket Center services and the current status, please visit us online at https:// www.epa.gov/dockets. If requested, the virtual hearing will be held on September 8, 2020. The hearing will convene at 9:00 a.m. Eastern Standard Time (EST) and will conclude at 3:00 p.m. EST. The EPA will announce further details on the virtual public hearing website at https:// www.epa.gov/stationary-sources-airpollution/industrial-commercial-andinstitutional-boilers-and-processheaters. Refer to the SUPPLEMENTARY INFORMATION section below for additional information. FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Mr. Jim Eddinger, Sector Policies and Programs Division (D243– 01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 Park, North Carolina 27711; telephone number: (919) 541–5426; and email address: eddinger.jim@epa.gov. SUPPLEMENTARY INFORMATION: Participation in virtual public hearing. Please note that the EPA is deviating from its typical approach because the President has declared a national emergency. Due to the current Centers for Disease Control and Prevention (CDC) recommendations, as well as state and local orders for social distancing to limit the spread of COVID–19, the EPA cannot hold inperson public meetings at this time. If a public hearing is requested, the EPA will begin pre-registering speakers for the hearing upon publication of this document in the Federal Register. To register to speak at the virtual hearing, please use the online registration form available at https://www.epa.gov/ stationary-sources-air-pollution/ industrial-commercial-and-institutionalboilers-and-process-heaters or contact Ms. Adrian Gates at (919) 541–4860 or by email at gates.adrian@epa.gov to register to speak at the virtual public hearing. The last day to pre-register to speak at the hearing will be September 8, 2020. On September 8, 2020, the EPA will post a general agenda for the hearing that will list pre-registered speakers in approximate order at https://www.epa.gov/stationary-sourcesair-pollution/industrial-commercialand-institutional-boilers-and-processheaters. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearing to run either ahead of schedule or behind schedule. Each commenter will have 5 minutes to provide oral testimony. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email) by emailing it to Jim Eddinger and Adrian Gates. The EPA also recommends submitting the text of your oral testimony as written comments to the rulemaking docket. The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral testimony and supporting information presented at the public hearing. Please note that any updates made to any aspect of the hearing will be posted online at https://www.epa.gov/ stationary-sources-air-pollution/ industrial-commercial-and-institutionalboilers-and-process-heaters. While the E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules EPA expects the hearing to go forward as set forth above, if requested, please monitor our website or contact Adrian Gates at 919–541–4862 or gates.adrian@ epa.gov to determine if there are any updates. The EPA does not intend to publish a document in the Federal Register announcing updates. If you require the services of a translator or a special accommodation such as audio description, please preregister for the hearing with Adrian Gates and describe your needs by August 31, 2020. The EPA may not be able to arrange accommodations without advance notice. Docket. The EPA has established a docket for this rulemaking under Docket ID No. EPA–HQ–OAR–2002–0058. All documents in the docket are listed in Regulations.gov. Although listed, some information is not publicly available, e.g., Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. Publicly available docket materials are available electronically in Regulations.gov. Instructions. Direct your comments to Docket ID No. EPA–HQ–OAR–2002– 0058. The EPA’s policy is that all comments received will be included in the public docket without change and may be made available online at https:// www.regulations.gov/, including any personal information provided, unless the comment includes information claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit electronically any information that you consider to be CBI or other information whose disclosure is restricted by statue. This type of information should be submitted by mail as discussed below. The EPA may publish any comment received to its public docket. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e., on the Web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/ commenting-epa-dockets. The https://www.regulations.gov/ website allows you to submit your VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 comment anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https:// www.regulations.gov/, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA’s public docket, visit the EPA Docket Center homepage at https:// www.epa.gov/dockets. The EPA is temporarily suspending its Docket Center and Reading Room for public visitors to reduce the risk of transmitting COVID–19. Written comments submitted by mail are temporarily suspended and no hand deliveries will be accepted. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https:// www.regulations.gov/. For further information and updates on EPA Docket Center services, please visit us online at https://www.epa.gov/dockets. The EPA continues to carefully and continuously monitor information from the CDC, local area health departments, and our Federal partners so that we can respond rapidly as conditions change regarding COVID–19. Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov/ or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, mark the outside of the digital storage media as CBI and then identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in Instructions above. If you submit any digital storage media that does not contain CBI, mark PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 52199 the outside of the digital storage media clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA’s electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver information identified as CBI only to the following address: OAQPS Document Control Officer (C404–02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention: Docket ID No. EPA– HQ–OAR–2002–0058. Note that written comments containing CBI and submitted by mail may be delayed and no hand deliveries will be accepted. 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 CEDRI Compliance and Emissions Data Reporting Interface CBI Confidential Business Information CEMS continuous emission monitoring system CFR Code of Federal Regulations CO Carbon Monoxide EPA Environmental Protection Agency HAP hazardous air pollutant(s) HCl hydrogen chloride Hg mercury ICI industrial, commercial, and institutional lb/MMBtu pounds per million British thermal units MACT maximum achievable control technology MPCRF Multipollutant Control Research Facility NAICS North American Industry Classification System NESHAP national emission standards for hazardous air pollutants OAQPS Office of Air Quality Planning and Standards OMB Office of Management and Budget PAH polycyclic aromatic hydrocarbons PM particulate matter ppb parts per billion ppm parts per million RDL representative detection level tpy tons per year TSM total selected metals UPL upper prediction limit VOC volatile organic compounds 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? II. Background E:\FR\FM\24AUP2.SGM 24AUP2 52200 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules A. What is the statutory authority for this action? III. Discussion of the Proposed Amendments A. Revisions to MACT Floor Emission Limits B. Beyond-the-Floor Emission Limits C. Revisions to Output-Based Emission Limits D. Proposed Response to the Amended Issue: CO as a Surrogate for Organic HAP E. Proposed Response to the Amended Issue: CO 130 ppm Threshold Emission Limits IV. Results and Proposed Decisions A. What are the resulting changes to emission limits? B. What compliance dates are we proposing? C. What other actions are we proposing? V. Summary of Cost, Environmental, and Economic Impacts A. What are the affected sources? B. What are the air quality impacts? C. What are the cost impacts? D. What are the secondary impacts? E. What are the economic impacts? F. What are the benefits? VI. Request for Comments VII. 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 I. General Information A. Executive Summary jbell on DSKJLSW7X2PROD with PROPOSALS2 1. Purpose of the Regulatory Action a. Need for Regulatory Action The NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters was promulgated on March 21, 2011, and amended on January 31, 2013, and November 20, 2015. Environmental groups and industry submitted petitions seeking judicial review of the NESHAP. On December 23, 2016, the D.C. Circuit amended its July 29, 2016 decision to remand instead of vacate certain VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 emission standards where it held that the EPA had improperly excluded certain units in establishing the emission standards and remanded the use of CO as a surrogate for organic HAP for further explanation. In March 2018, the court in a separate case remanded the EPA’s decision to set a limit of 130 parts per million (ppm) CO as a minimum standard for certain subcategories for further explanation. The courts did not set specific deadlines for the EPA to issue revised regulations as part of either remand. In response to these remands, the EPA is proposing to amend several emission standards consistent with the court’s opinion and proposing responses to the two issues remanded for further explanation. b. Legal Authority The statutory authority for this proposed rulemaking is section 112 of the CAA. Title III of the CAA Amendments was enacted to reduce nationwide air toxic emissions. Section 112(d)(2) of the CAA directs the EPA to develop NESHAP which require existing and new major sources to control emissions of HAP using MACT based standards. This NESHAP applies to all ICI boilers and process heaters located at major sources of HAP emissions.1 2. Summary of the Major Provisions of the Regulatory Action in Question TABLE 1—SUMMARY OF SUBCATEGORIES WITH PROPOSED REVISIONS TO EMISSION LIMITS—Continued Subcategory New-Biomass Suspension Burner. New-Biomass Hybrid Suspension Grate. New-Biomass Dutch Oven/ Pile Burner. New-Biomass Dutch Oven/ Pile Burner. New-Biomass Dutch Oven/ Pile Burner. New-Liquid ............................ New-Heavy Liquid ................ New-Process Gas ................. Existing-Solid ........................ Existing-Coal ......................... Existing-Coal Stoker ............. Existing-Dry Biomass Stoker Existing-Wet Biomass Stoker Existing-Biomass Fluidized Bed. Existing-Biomass Suspension Burners. Existing-Biomass Dutch Oven/Pile Burner. Existing-Liquid ...................... Existing-Heavy Liquid ........... Existing-Non-continental Liquid. Existing-Process Gas ........... Pollutant where a limit is proposed to change CO, TSM. CO. PM. PM. CO, PM. HCl. PM, TSM. PM. HCl, Hg. PM. CO. TSM. CO, PM, TSM. CO, PM, TSM. PM, TSM. PM. Hg. PM. PM. PM. 3. Costs and Benefits The EPA is proposing to revise 34 different emission limits which it had previously promulgated in 2011 and amended in, 2013. Of these 34 emission limits, 28 of the limits would become more stringent and six of the limits would become less stringent. EPA is also proposing that facilities would have up to 3 years after the effective date of the final rule to demonstrate compliance with these revised emission limits. A list of each combination of subcategory and pollutant where the limits have proposed revisions is shown in Table 1. We have estimated certain cost and benefits of the proposed rule, and these are found in Table 2. Present values (PV) of the net co-benefits, in 2016 dollars and discounted to 2020, are from $655 million to $1,575 million when using a 7-percent discount rate and from $751 million to $1,871 million when using a 3-percent discount rate. The equivalent annualized values (EAV) of the net co-benefits are from $78 million to $194 million per year when using a 7-percent discount rate and from $92 million to $232 million per year when using a 3-percent discount rate. All of TABLE 1—SUMMARY OF SUBCATthese estimates are in 2016 dollars. The EGORIES WITH PROPOSED REVI- monetized benefits estimate reflects an SIONS TO EMISSION LIMITS annual average of 251 tons of fine particulate matter (PM2.5) emission Pollutant reductions per year and 393 tons of where a limit Subcategory is proposed to sulfur dioxide (SO2) emission reductions per year. These benefits are change referred to as ancillary co-benefits since New-Solid ............................. HCl. these pollutants are not targeted for New-Dry Biomass Stoker ..... TSM. control in the proposal. The New-Biomass Fluidized Bed CO, PM, TSM. unmonetized benefits include: Reduced exposure to HAP, including mercury 1 See 75 FR 32016 and section 63.7575 ‘‘What (Hg), hydrochloric acid (HCl), non-Hg definitions apply to this subpart’’ of 40 CFR part 63, metals (e.g., antimony, cadmium), subpart DDDDD for definitions of ICI boilers and formaldehyde, benzene, and polycyclic process heaters. PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 52201 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules organic matter; reduced climate effects due to reduced black carbon emissions; reduced ecosystem effects; and reduced visibility impairments. We represent the present value of unmonetized benefits from affected HAP emission reductions as a C, and this is part of the net benefits estimate. We represent the equivalent annualized value of unmonetized benefits from affected HAP emission reductions as a D, and this is part of the net benefits estimate. These estimates also include climate co-disbenefits resulting from an increase in carbon dioxide (CO2) emissions, a secondary impact from electricity use by additional control devices in response to the proposal. This disbenefit is $0.09 million at a 3-percent discount rate and $0.01 million at a 7-percent discount rate. More information on these impacts can be found in section V of this preamble and in the Regulatory Impact Analysis (RIA) for this proposal. TABLE 2—SUMMARY OF PRESENT VALUES AND EQUIVALENT ANNUALIZED VALUES FOR ANNUAL COSTS, MONETIZED ANCILLARY CO-BENEFITS, AND MONETIZED NET BENEFITS (INCLUDING ANCILLARY CO-DISBENEFITS) FOR THE PROPOSED RULE [Millions of 2016 dollars] 1 2 Present Value ............................................... Equivalent Annualized Value ........................ 3% Discount rate 7% Discount rate Targeted Benefits 3 ....................................... C C Ancillary Co-Benefits .................................... Cost 4 ............................................................ Net Benefits 5 ................................................ $730 to $1,650 $130 $600 to $1,520 + C $630 to $1,100 $100 $530 to $1,000 + C Targeted Benefits 6 ....................................... Ancillary Co-Benefits .................................... D $100 to 240 D $90 to 180 Costs ............................................................ Net Benefits .................................................. 18 $80 to 220 + D 17 $70 to 160 + D 1 All estimates in this table are rounded to one decimal point, so numbers may not sum due to independent rounding. estimates reflect the amendments to the ICI Boilers MACT standard included in this proposal from a baseline that includes the control technologies applied to meet the MACT standard. 3 C represents the present value of unquantified benefits from reductions in targeted HAP emissions. 4 The annualized present value of costs and benefits are calculated over an 8-year period from 2021 to 2028. 5 The total monetized ancillary co-benefits reflect the human health benefits associated with reducing exposure to PM 2.5 through reductions of directly emitted PM2.5 and SO2. Monetized ancillary co-benefits include many, but not all, health effects associated with PM2.5 exposure. Co-benefits are shown as a range from Krewski et al. (2009) to Lepeule et al. (2012). We do not report the total monetized ancillary co-benefits by PM2.5 species. The ancillary climate co-disbenefits from additional CO2 emissions resulting from control device operations are included in the results given the rounding convention employed in this table as stated in footnote a. The net benefits calculation consists of the targeted benefits and ancillary co-benefits minus the social costs. 6 D represents the equivalent annualized value of unquantified benefits from reductions in targeted HAP emissions. 2 All B. Does this action apply to me? jbell on DSKJLSW7X2PROD with PROPOSALS2 Table 3 of this preamble lists the NESHAP and associated regulated industrial source categories that are the subject of this proposal. Table 3 is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that this proposed action is likely to affect. The proposed standards, once promulgated, will be directly applicable to the affected sources. As defined in the Initial List of Categories of Sources Under Section 112(c)(1) of the Clean Air Act Amendments of 1990 (see 57 FR 31576, July 16, 1992) and Documentation for Developing the Initial Source Category List, Final Report (see EPA–450/3–91–030, July VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 1992), the Industrial Boiler source category includes boilers used in manufacturing, processing, mining, and refining or any other industry to provide steam, hot water, and/or electricity. The Institutional/Commercial Boilers source category includes, but is not limited to, boilers used in commercial establishments, medical centers, research centers, institutions of higher education, hotels, and laundries to provide electricity, steam, and/or hot water. Waste heat boilers are excluded from this definition. The Process Heaters source category includes, but is not limited to, secondary metals process heaters, petroleum and chemical industry process heaters, and other process heaters. A process heater is PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 defined as an enclosed device using controlled flame, and the unit’s primary purpose is to transfer heat indirectly to a process material (liquid, gas, or solid) or to a heat transfer material (e.g., glycol or a mixture of glycol and water) for use in a process unit, instead of generating steam. Process heaters do not include units used for comfort heat or space heat, food preparation for on-site consumption, or autoclaves. Waste heat process heaters are excluded from this definition. A boiler or process heater combusting solid waste is not a boiler unless the device is exempt from the definition of a solid waste incineration unit as provided in section 129(g)(1) of the CAA. E:\FR\FM\24AUP2.SGM 24AUP2 52202 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 3—SOURCE CATEGORIES AFFECTED BY THIS PROPOSED ACTION Source category NESHAP Any industry using a boiler or process heater as defined in the final rule. Industrial, Commercial, and Institutional Boilers and Process Heaters.. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... 1 North 211 321 322 325 324 316, 326, 339 331 332 336 221 622 611 Examples of potentially regulated entities Extractors of crude petroleum and natural gas. Manufacturers of lumber and wood products. Pulp and paper mills. Chemical manufacturers. Petroleum refineries, and manufacturers of coal products. Manufacturers of rubber and miscellaneous plastic products. Steel works, blast furnaces. Electroplating, plating, polishing, anodizing, and coloring. Manufacturers of motor vehicle parts and accessories. Electric, gas, and sanitary services. Health services. Educational services. American Industry Classification System. 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 proposed action at https://www.epa.gov/ industrial-commercial-and-institutionalboilers-and-process-heaters. Following publication in the Federal Register, the EPA will post the Federal Register version of the proposal and key technical documents at this same website. A redline version of the regulatory language that incorporates the proposed changes in this action is available in the docket for this action (Docket ID No. EPA–HQ–OAR–2002–0058). jbell on DSKJLSW7X2PROD with PROPOSALS2 NAICS code 1 II. Background On March 21, 2011, the EPA established final emission standards for ICI boilers and process heaters at major sources, reflecting the application of MACT—the Boiler MACT (76 FR 15608). On January 31, 2013, the EPA promulgated final amendments to the Boiler MACT (78 FR 7138). On November 20, 2015, the EPA promulgated additional amendments to the Boiler MACT (80 FR 72789) in response to certain reconsideration issues, but other issues remained unresolved due to pending litigation at the time these final amendments were published. On July 29, 2016, the D.C. Circuit issued its decision in U.S. Sugar Corp v. EPA, 830 F.3d 579. In that decision, the court upheld the EPA’s 2013 Boiler MACT against all challenges brought by industry petitioners, and virtually all VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 challenges brought by environmental petitioners. However, the court vacated the MACT floor emission limits for those subcategories where the EPA had excluded certain units from its MACTfloor calculation because those units burned less than 90 percent of the subcategory defining fuel. U. S. Sugar Corp. v. EPA, 830 F.3d at 631. On December 23, 2016, the D.C. Circuit granted EPA’s motion for rehearing on remedy and remanded without vacatur these affected MACT standards. 844 F.3d 268. Therefore, these MACT standards have remained in effect since the court’s decision. Additionally, the court in U.S. Sugar remanded the use of CO as a surrogate for non-dioxin organic HAP to the EPA for the limited purpose of addressing the potential availability of postcombustion control technologies that could control CO. In a subsequent decision on March 16, 2018, the D.C. Circuit remanded the EPA’s decision to set a limit of 130 ppm CO as a surrogate for non-dioxin organic HAP for certain subcategories, again asking the Agency to better explain its analysis supporting its decision. Sierra Club v. EPA, 884 F.3d 1185. In this action, the EPA is proposing changes to certain emissions limits in the final rule and is providing additional explanation of certain issues relating to the CO standards in response to these remands. The EPA is also proposing several technical corrections. A. What is the statutory authority for this action? Section 112 of the CAA establishes a regulatory process to address emissions of HAP from stationary sources. CAA section 112(d) requires the Agency to PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 promulgate technology-based NESHAP for major sources. ‘‘Major sources’’ are defined in CAA Section 112(a) as sources that emit or have the potential to emit 10 tons or more per year (tpy) of a single HAP or 25 tpy or more of any combination of HAP. For major sources, the technology-based NESHAP must require the maximum degree of reduction in emissions of HAP achievable (after considering cost, energy requirements, and non-air quality health and environmental impacts). These standards are commonly referred to as MACT standards. The MACT ‘‘floor’’ is the minimum control level allowed for MACT standards promulgated under CAA section 112(d)(3) and may not be based on cost considerations. For new sources, the MACT floor cannot be less stringent than the emissions control that is achieved in practice by the best controlled similar source. The MACT floor for existing sources may be less stringent than floors for new sources but may not be less stringent than the average emissions limitation achieved by the best-performing 12 percent of existing sources in the category or subcategory (or the best-performing five sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, the EPA must also consider control options that are more stringent than the floor (i.e., ‘‘beyond-the-floor’’ options) under CAA section 112(d)(2). We may establish beyond-the-floor standards more stringent than the floor based on considerations of the cost of achieving the emission reductions, any non-air quality health and environmental impacts, and energy requirements. E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules III. Discussion of the Proposed Amendments jbell on DSKJLSW7X2PROD with PROPOSALS2 A. Revisions to MACT Floor Emission Limits 1. Revisions to MACT Floor Ranking Methodology for Co-Fired Units Many of the affected sources subject to numerical limits under the NESHAP involve boilers and process heaters that co-fire multiple fuel types. In the January 2013 final rule amendments, the EPA defined each subcategory using a threshold of at least 10 percent of a subcategory-defining fuel, on an annual heat input basis. These definitions were set up in a hierarchical manner. Solid fuel units must burn at least 10-percent solid fuel. Coal and solid fossil fuel units must burn at least 10-percent coal or another solid fossil fuel. Biomass units must burn at least 10-percent biomass, but less than 10-percent coal. Liquid fuel units may burn any liquid fuel but less than 10-percent coal or fossil solid, and less than 10-percent biomass. The MACT floor analysis conducted in the 2013 rulemaking used a 90-percent fuel threshold, instead of the regulatory definition of 10 percent, to group test data into subcategories for ranking the best performers and calculating the MACT floors. This approach excluded several units that were in the subcategory from the ranking analysis, which in turn excluded these boilers from consideration in upper prediction limit (UPL) calculations to establish the MACT floor. The D.C. Circuit in U.S. Sugar stated that, if EPA includes a source in a subcategory, it must consider whether any source in that subcategory is a bestperforming source which would then need to be accounted for in setting the MACT floor. U.S. Sugar v. EPA, 830 F.3d at 631. Following the EPA’s request for rehearing, the court remanded standards affected by its decision to the EPA for further consideration, and the EPA is now proposing to revise the affected standards consistent with the court’s opinion. For this proposal, the same dataset used as the basis for the 2013 final rule was used as the basis of the calculations for the proposed revised standards.2 The EPA performed a more detailed review of the units in the dataset that had previously been excluded from the rankings, with emphasis on the newly 2 Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, and Fuel Analysis Data Reporting under ICR No. 2286.01 and ICR No.2286.03 (OMB Control Number 2060–0616) (version 8). Docket ID No. EPA–HQ–OAR–2002– 0058–3830. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 identified best performers. While checking background test reports, the EPA corrected some database errors, filled information gaps for certain cofired fuel blends, and adjusted CO instrument span measurements. However, since the proposed revisions are solely to address the remand in U.S. Sugar, we re-ran the MACT floor analysis to incorporate data that had been previously excluded. The rankings of each subcategory were revised to incorporate data from tests that fired at least 10 percent of a subcategorydefining fuel. This change in criteria impacted the number of units with emission test data for certain subcategories. In many cases test data for co-fired units in the 2013 Emissions Database did not quantify the exact fuel input breakdown.3 The EPA reviewed test reports that were included as background data materials for the 2013 Emissions Database and conducted outreach with selected facilities in order to verify to which subcategory the various test data belonged. Appendix B of the docketed memorandum, Revised MACT Floor Analysis (2019) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source (2019 MACT Floor Memo), details the revised ranking of each subcategory and compares the ranking to the previous ranking assignment from the January 2013 final rule. As was done in the January 2013 final rule, devices that were co-firing solid waste materials were excluded from the ranking unless the device was exempted from the definition of a solid waste incineration unit as provided in section 129(g)(1) of the CAA. As part of the revisions to the ranking analysis, the EPA also made corrections to some of the emissions data, as part of its data quality review of the revised set of best performing units in each subcategory. The EPA investigated historical notes in the 2013 Emissions Database about whether certain test results were valid or were previously excluded due to data quality concerns. When historical notes had excluded data, those exclusions were carried forward into the revised analysis supporting the proposal. Because some new best performing units were identified in the ranking analysis, the EPA also reviewed test reports that were available in the rulemaking docket to verify reported emission results in the database as well as oxygen adjustment factors, and CO instrument span and CO calibration data. EPA made corrections 3 Ibid. PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 52203 to the values used in the MACT floor analysis when these back-up documents suggested a correction was needed. In addition to data available from the docketed data resources, the EPA also received data correction files and a small number of additional tests from members of the American Forest and Paper Association. The EPA reviewed the additional data provided, including any supporting emission test reports to evaluate if the data were accurate and complete and representative prior to including the data in the revised ranking analysis. A summary of data changes made since version 8 of the database is available in the docketed memorandum, Summary of 2019 Emission Database Changes for Major Source Boilers and Process Heaters. In addition, a summary of the expected impacts of these data changes is available in the Regulatory Impact Analysis for the Proposed ICI Boilers NESHAP Reconsideration, which is available in the docket for this action. The changes include an increase in compliance costs as well as an increase in emission reductions as a result of the more stringent emission limits. a. Existing Sources Because the rankings shifted dramatically, the number of units in each of the subcategories changed, as well as the specific units that comprised the top 12 percent within the subcategory. Appendix B–1 of the 2019 MACT Floor Memo summarizes the revised number of units in the top 12 percent for each combination of subcategory and pollutant. The remainder of the worksheets in Appendix B indicate which units are identified to be among the top 12 percent. Once the top 12 percent of units were identified, each unique combination of pollutant and subcategory data was reviewed to determine the distribution of the dataset and then calculate the UPL. The procedures for determining the data distribution and calculating the UPL remain the same as they did for the January 2013 final rule, with the exception of ‘‘limited datasets’’ which are those that consisted of less than seven test runs. The procedures for determining the distribution and calculating the UPL are detailed in EPA’s Response to Remand of the Record for Major Source Boilers, July 14, 2014 available in the docket for this action. Additional considerations for limited datasets are discussed in section III.A.2 of this preamble. The actual calculations and distribution assignments for each pollutant and subcategory combination are shown in E:\FR\FM\24AUP2.SGM 24AUP2 52204 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 Appendix C of the 2019 MACT Floor Memo. The EPA is not soliciting comment on its use of the same methodology that it used to set the January 2013 standards, but is soliciting comment on the proposed revisions to the standards the Agency is proposing to address concerning the court’s remand in U.S. Sugar. Once the UPL values were calculated, the EPA reviewed whether any additional fuel variability factors were available to multiply by the calculated UPL for Hg, HCl, and total selected metals 4 (TSM). The methodology for computing the fuel variability factor did not change since the January 2013 final rule. Instead, any changes in the fuel variability factors occurred because of changes to the units that constituted the top 12 percent for each subcategory and were, therefore, eligible for consideration in the fuel variability factor analysis. The fuel variability factor calculations are shown in Appendix A of the 2019 MACT Floor Memo. Fuel variability factors were available for solid and liquid fuel subcategories for Hg and HCl and for biomass fluidized bed, coal, and heavy liquid subcategories for TSM. b. New Sources Similar to existing sources, the reranking of the data for each new source subcategory impacted the specific units that were identified as the lowest emitting for each combination of pollutant and subcategory. Additionally, as in the January 2013 final rule, the EPA did not allow units with a nitrogen oxides-to-CO ratio above 50 to represent a best performing boiler for CO. Instead, the EPA picked the next lowest ranked unit for the Coal Stokers. Additionally, as in the January 2013 final rule, the EPA only considered units with at least three test runs to serve as the basis of the new source floor except for cases where no other data were available. This occurred only for the TSM UPL calculations for new Biomass Suspension Burner. In that case, the second ranked unit was selected. The revisions to the emissions standards proposed here are for the limited purpose of addressing the court’s remand in U.S. Sugar, and the EPA is not proposing or soliciting comment on other aspects of the standards or methodology used to calculate the standards. Once the best controlled similar source for each subcategory was identified, each unique combination of 4 Total selected metals is the sum of the non-Hg HAP metals—arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and selenium. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 pollutant and subcategory data was reviewed to determine the distribution of the dataset and then calculate the UPL. The procedures for determining the data distribution and calculating the UPL remain the same as for the January 2013 final rule, with the exception of limited datasets that consisted of less than seven test runs or in cases where the calculated new source UPL exceeded the existing source UPL for the same subcategory. The procedures for determining the distribution and calculating the UPL are detailed in the docketed memorandum, Revised MACT Floor Analysis (2019) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source. Many of the new source UPL calculations involved limited datasets and additional considerations for limited datasets are discussed in section III.A.2 of this preamble. The actual calculations and distribution assignments for each pollutant and subcategory combination are shown in Appendix E of the 2019 MACT Floor Memo. This appendix worksheet for each UPL calculation also shows the ranking of each unit. Once the UPL values were calculated, the EPA reviewed whether any additional fuel variability factors were available to multiply by the calculated UPL for Hg, HCl, and TSM. The methodology for computing the fuel variability factor did not change since the January 2013 final rule. Instead, any changes in the fuel variability factors occurred because of changes to the unit selected to represent the best controlled similar source and were, therefore, eligible for consideration in the fuel variability factor analysis for new sources. The fuel variability factor calculations are shown in Appendix A of the 2019 MACT Floor Memo. Fuel variability factors were available for liquid fuel and coal subcategories for Hg and HCl, and the heavy liquid subcategory for TSM. The EPA also incorporated the same procedures as the January 2013 final rule to ensure that the available measurement methods would provide accurate emissions measurements at the levels set for the various standards. The procedures are discussed in detail at 76 FR 80611 and the calculated values are presented in technical memoranda in the docket.5 The procedures remained the same, but which unit represents the new source floor did change since January 2013; so, the actual representative detection level (RDL) 5 See Docket ID Item Nos.: EPA–HQ–OAR–2002– 0058–3837 and EPA–HQ–OAR–2002–0058–3839. PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 calculation accordingly changed as well. The revised calculations for 3 times the RDL are presented in the documented memorandum. After computing the RDL, the UPL calculations were compared to a value equal to 3 times the RDL. In the case of new sources, if the UPL was below the 3 times RDL value then the MACT floor was set equal to 3 times the RDL. Lastly, the EPA compared the calculated UPL, or 3 times RDL values where appropriate, to the existing source emission limits for the same pollutant and subcategory. If the new source floor was larger than the existing source floor, the EPA reviewed the data further as discussed in the UPL methodology for limited datasets in section III.A.2 of this preamble to evaluate if the unit truly reflected the best controlled similar source as determined by the Administrator and to evaluate if the UPL calculations required any adjustments to ensure that the UPL did not result in a less stringent standard for new sources. In addition to the tests conducted on limited datasets, two subcategories for new source limits required additional evaluation, as discussed below. Specific names of the facility and boiler names refer to how the boilers are identified in the MACT floor analysis to allow the reader to find these units in the related technical support memoranda. The MACT floor dataset for particulate matter (PM) from new fluidized bed boilers designed to burn biomass includes 18 test runs from a single boiler ‘‘ORGeorgiaPacificWauna Mill, EU35—Fluidized Bed Boiler’’ (EU35) that we identified as the best performing unit based on average emissions. The calculated UPL for new sources exceeded the UPL calculated for existing units in the same subcategory. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit. Our analysis showed that this unit, identified as the best performing unit based on average emissions, has a variance that is 3 orders of magnitude higher than the second ranked unit ‘‘WIGPGreenBay2818, B10—Wastepaper Sludge-Fired Boiler 10’’ (B10) and an overall average (considering all stack tests, not just the minimum stack test average) that is approximately 4 times higher than the second ranked unit. This information indicates that the second ranked unit, B10, has a more consistent level of performance than the top ranked unit, EU35, and the resulting UPL calculations support this. The calculated UPL is lower for the second ranked unit, B10, than for the top E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 ranked unit, EU35. For these reasons, we determined that the unit with the lowest average, EU35, is not the best performing source for this subcategory and pollutant and we are instead identifying B10 as the best performing source. The MACT floor dataset for PM from new stoker boilers designed to burn wet biomass includes nine test runs from a single boiler ‘‘IAMonsantoMuscatine, Boiler #8 EP–195’’ that we identified as the best performing unit based on average emissions. The calculated UPL for new sources exceeded the UPL calculated for existing units in the same subcategory. The UPL based on a lognormal equation was 10.2 times higher than the mean. After reviewing the distribution of the dataset, we found that the distribution was incorrectly flagged as lognormally distributed instead of normally distributed. The UPL based on the normal distribution no longer exceeds the UPL calculation for existing sources. The UPL based on a normal equation was 2.36 times higher than the mean. After correcting the distribution, we also evaluated the variance of this unit, which was 4 times lower than the variance of the next lowest ranked unit. For these reasons, we determined that the UPL based on the normal distribution was the appropriate basis for the new source floor for this subcategory. 2. UPL Methodology for Limited Datasets In August 2013, the D.C. Circuit issued its decision in National Ass’n. of Clean Water Agencies (NACWA) v. EPA, which addressed challenges to the EPA’s 2011 Sewage Sludge Incinerator (SSI) rule, issued under section 129 of the CAA. In NACWA v. EPA, the court remanded the EPA’s use of the UPL methodology to the Agency for further explanation of how the methodology reflected the average emissions limitation achieved by the bestperforming 12 percent of sources (for existing sources) and the average emissions limitation achieved by the best-performing similar source (for new sources). NACWA v. EPA, 734 F.3d 1115, 1151. Because the UPL methodology used in the SSI rule was the same as that used in the major source Boiler MACT, the EPA requested a remand of the record in U.S. Sugar v. EPA in order to address the court’s decision in NACWA v. EPA. The EPA prepared a memorandum explaining the methodology for the UPL. This memorandum, EPA’s Response to Remand of the Record for Major Source Boilers, provides a detailed rationale to use the UPL as the basis of setting a VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 MACT floor for new and existing sources, and the methodology and the explanation in the memorandum were upheld by the D.C. Circuit in U.S. Sugar v. EPA. 830 F.3d at 639. Following the UPL memorandum, the EPA issued a subsequent memorandum specifically addressing the application of the UPL methodology when setting MACT emission limits with limited datasets, Approach for Applying the Upper Prediction Limit to Limited Datasets. In that memorandum, the EPA concluded that there are additional considerations when setting MACT floors for limited datasets. The EPA is not, in this action, proposing any revisions to or soliciting comment on either the EPA’s Response to Remand of the Record for Major Source Boilers memorandum or the limited datasets memorandum. Rather, the EPA is proposing limited revisions to certain Boiler MACT standards to address the specific issue remanded to the Agency by the court in U.S. Sugar v. EPA. The docketed memorandum, Approach for Applying the Upper Prediction Limit to Limited Datasets for Boilers and Process Heaters at Major Sources, discusses the generic methods in the previously issued limited dataset memorandum, as well as a summary of the findings for certain boiler and process heater subcategories. A summary of those findings is also discussed here. For the ICI Boilers and Process Heaters source categories, we have limited datasets for the following subcategories and pollutants for both existing and new sources: process gas (Hg, HCl, TSM, and PM), biomass suspension burner (TSM), dry biomass stoker (TSM, PM, and CO), and coal fluidized bed coal refuse (CO). For the ICI Boilers and Process Heaters source categories, we have limited datasets for the following subcategories and pollutants for new sources: Solid (Hg and HCl), liquid (Hg and HCl), heavy liquid (TSM and PM), light liquid (TSM and PM), biomass dutch oven/pile burner (TSM), biomass fuel cell (TSM), biomass fluidized bed (TSM), biomass suspension burner (TSM), biomass suspension grate (CO), wet biomass stoker (TSM), and coal (TSM and PM). Therefore, we evaluated these specific datasets to determine whether it is appropriate to make any modifications to the UPL approach used to calculate the MACT floors. For each dataset, we performed the following steps: Selected the data distribution that best represents the dataset; ensured that the correct equation for the distribution was then applied to the data; and compared individual components of the limited PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 52205 dataset to determine if the standards based on the limited dataset reasonably represent the performance of the units included in the dataset. The results of the limited dataset analyses are presented below for each subcategory and pollutant. The MACT floor datasets for Hg, HCl, and PM from existing and new boilers designed to burn process gas include three test runs from a single boiler. In addition, there are no other process gas units in the rankings to select from for these pollutants. Using the available data, we first determined the correct distribution and ensured that we used the correct equation for each distribution. The MACT floor dataset for TSM from existing and new boilers designed to burn process gas only includes two test runs. We assumed a distribution of lognormal for this dataset. We then calculated the UPLbased limits which range from 1.2 to 3 times the average (mean) of all test runs from the best performing source. This result indicates that the emission limits are not unreasonable compared to the actual performance of the unit upon which the limits are based and are within the ranges that we see when we evaluate larger datasets using our MACT floor calculation procedures. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from existing and new suspension burner boilers designed to burn biomass includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. In addition, there are no other biomass suspension burner units in the rankings to select from for this pollutant because the other unit with test data only has two test runs, and units with less than three test runs were not considered for UPL calculations if other data are available (see discussion in section III.A.1 of this preamble). Using the available data, we first determined the correct distribution and ensured that we used the correct equation for each distribution. We then calculated the UPL-based limit which is 1.7 times the short-term average emissions from the best performing source. This result indicates that the emission limit is not unreasonable compared to the actual performance of the unit upon which the limit is based and is within the range that we see when we evaluate larger datasets using our MACT floor calculation procedures. Therefore, we determined that the emission limit reasonably accounts for E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 52206 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from existing and new stoker boilers designed to burn dry biomass includes three test runs from a single boiler. In addition, there are no other dry biomass stoker units in the rankings to select from for this pollutant. Using the available data, we first determined the correct distribution and ensured that we used the correct equation for each distribution. We then calculated the UPL-based-limit, which is approximately 2 times the short-term average emissions from the best performing source, indicating that the emission limit is not unreasonable compared to the actual performance of the unit upon which the limit is based and is within the range that we see when we evaluate larger datasets using our MACT floor calculation procedures. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor datasets for PM and CO from existing and new stoker boilers designed to burn dry biomass include three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit for each pollutant, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance for each pollutant, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limits reasonably account for variability and that no changes to our standard floor calculation procedure were warranted for this subcategory and pollutants. The MACT floor dataset for CO from existing and new fluidized bed boilers designed to burn coal refuse includes three test runs from a single boiler. In addition, there are no other units in the rankings to select from for this pollutant. Using the available data, we first determined the correct distribution and ensured that we used the correct equation for the distribution. We then calculated the UPL-based limit which is approximately 1.5 times the short-term average emissions from the best performing source, indicating that the VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 emission limit is not unreasonable compared to the actual performance of the unit upon which the limit is based and is within the range that we see when we evaluate larger datasets using our MACT floor calculation procedures. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for Hg from new boilers designed to burn solid fuel includes six test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to our standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for HCl from new boilers designed to burn solid fuel includes six test runs from a single boiler ‘‘ARPotlatchForestWarren, Wellons Boiler’’ (Wellons Boiler) that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we compared the calculated UPL to the short-term average emissions and found that the unit had a UPL that was 81 times higher than the lowest short-term average emission test and that this ratio is not within the range that we see when we evaluate larger datasets using our MACT floor calculation procedures. Based on this, we evaluated the variance of this unit and concluded that further consideration of the best performer selection was warranted. The variance of the top ranked unit was 6 orders of magnitude higher than the variance of the next ranked unit ‘‘TXDibollTempleInland, PB–44’’ (PB–44). In addition, the Wellons Boiler six test runs were from two separate stack tests, and while the unit was the top ranked unit due to one of the stack test averages being very low, the other stack test average was 6.2 times higher. The high degree of variance in the dataset for the unit with the lowest average, Wellons Boiler, prompted us to question whether this PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 unit was, in fact, the best performing unit and to evaluate the dataset for PB– 44. The dataset for PB–44 includes three test runs and the average emissions are only about 7 percent higher than the Wellons Boiler lowest stack test average. However, the PB–44 average emissions are actually 97 percent lower when comparing to the Wellons Boiler average for both stack tests. This information indicates that the second ranked unit, PB–44, has a more consistent level of performance than the top ranked unit, Wellons Boiler, and the resulting UPL calculations support this. The HCl UPL value is lower for PB–44 than for Wellons Boiler and the Wellons Boiler UPL exceeded the UPL for existing solid fuel boilers. For these reasons, we determined that the unit with the lowest average, Wellons Boiler, is not the best performing source for this pollutant and we are instead determining PB–44 to be the best performing source. The MACT floor dataset for Hg from new boilers designed to burn liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit. Our analysis showed that this unit, identified as the best performing unit based on average emissions, and the second ranked unit both have similar and extremely low variance, indicating consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for HCl from new boilers designed to burn liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for TSM from new boilers designed to burn heavy E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best unit based on average emissions, had a slightly higher variance than the next ranked unit. Therefore, we also evaluated the second ranked unit and determined its distribution and applied the equation for its distribution. Comparing the calculated UPL values for the top two units, the best performing unit resulted in the lower UPL. While its variance was slightly higher, the top ranked unit’s lower overall emissions and resulting UPL calculations indicate it is the best performer. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for PM from new boilers designed to burn heavy liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from new boilers designed to burn light liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, and the second ranked unit have nearly equivalent variance, indicating consistent performance. Therefore, we determined that the emission limit reasonably accounts for VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for PM from new boilers designed to burn light liquid fuel includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from new dutch oven boilers designed to burn biomass includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from new biomass fuel cell boilers includes six test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 52207 calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from new fluidized bed boilers designed to burn biomass includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best performing unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this pollutant and subcategory. The MACT floor dataset for TSM from new suspension burners designed to burn biomass includes three test runs from a single boiler. In addition, there are no other biomass suspension burner units in the rankings to select from for this pollutant. Using the available data, we first determined the correct distribution and ensured that we used the correct equation for each distribution. We then calculated the UPL-based limit which is 1.7 times the short-term average emissions from the best performing source, indicating that the emission limit is not unreasonable compared to the actual performance of the unit upon which the limit is based and is within the range that we see when we evaluate larger datasets using our MACT floor calculation procedures. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to our standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for TSM from new stoker boilers designed to burn wet biomass includes six test runs from a single boiler ‘‘GAGPCellulose Brunswick, U700—No. 4 Power Boiler’’ (U700—No. 4 Power Boiler) that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for the distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. We note that the second and third ranked units each have less than three test runs, and units with less than three test runs were not considered for UPL calculations if other data are available (see discussion in section E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 52208 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules III.A.1 of this preamble). Our analysis showed that this unit, identified as the best performing unit based only on average emissions, has a higher variance than the fourth ranked unit ‘‘MESDWarrenSomerset, No. 2 Power Boiler’’ (No. 2 Power Boiler) and an overall average (considering all stack tests, not just the minimum stack test average) that is approximately 18 percent higher than the fourth ranked unit. This information indicates that the fourth ranked unit, No. 2 Power Boiler, has a more consistent level of performance than the top ranked unit, U700—No. 4 Power Boiler, and the resulting UPL calculations support this. The calculated UPL is lower for the fourth ranked unit, No. 2 Power Boiler, than for the top ranked unit, U700—No. 4 Power Boiler. For these reasons, we determined that the unit with the lowest average, U700—No. 4 Power Boiler, is not the best performing source for this subcategory and pollutant and we are instead determining that No. 2 Power Boiler is the best performing source. The MACT floor dataset for CO from new suspension grate boilers designed to burn biomass includes three test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit, comparing it to other boilers in the same subcategory. Our analysis showed that this unit, identified as the best unit based on average emissions, also had the lowest variance, indicating that not only did it have the lowest average emissions but also the most consistent performance. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for TSM from new coal boilers includes six test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit and concluded that further consideration of the best performer selection was warranted. The variance of the top ranked unit was approximately 3 times higher than the variance of the next ranked unit. The degree of variance in the dataset for the unit with the lowest average prompted us to question whether this unit was, in fact, the best performing unit and to evaluate the second ranked unit. The VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 second ranked unit includes 3 test runs. We calculated the UPL using data for the second ranked unit, however, and the resulting UPL was higher than when using data from the top ranked unit. While its variance was higher, the top ranked unit’s lower overall emissions and resulting UPL calculations indicate it is the best performer. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this subcategory and pollutant. The MACT floor dataset for PM from new coal boilers includes six test runs from a single boiler that we identified as the best performing unit based on average emissions. After determining the correct distribution and ensuring that we used the correct equation for each distribution, we evaluated the variance of this unit and concluded that further consideration of the best performer selection was warranted. The variance of the top ranked unit was approximately 2.5 times higher than the variance of the next ranked unit. The degree of variance in the dataset for the unit with the lowest average prompted us to question whether this unit was, in fact, the best performing unit and to evaluate the second ranked unit. The second ranked unit includes three test runs. We calculated the UPL using data for the second ranked unit, however, and the resulting UPL was higher than when using data from the top ranked unit. Therefore, while its variance was higher, the top ranked unit’s lower overall emissions and resulting UPL calculations indicate it is the best performer. Therefore, we determined that the emission limit reasonably accounts for variability and that no changes to the standard floor calculation procedure were warranted for this subcategory and pollutant. The Process Gas and Coal Fluidized Bed subcategories for existing and new sources and the Heavy Liquid Fuel, Light Liquid Fuel, Pulverized Coal Boilers, and Coal Stoker subcategories for new sources have limited datasets for CO. However, the best performers have very low CO emissions and the emission limits were set equal to a minimum CO level; the applicable methodology is discussed in section III.E of this preamble. B. Beyond-the-Floor Emission Limits We reviewed the recalculated MACT floor emission limits that are less stringent than those in the January 2013 final rule in order to assess whether a beyond-the-floor option was technically achievable and cost-effective. To assess whether the January 2013 limits were PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 technically achievable we reviewed the compliance data available to the EPA through the Compliance and Emissions Data Reporting Interface (CEDRI) and WebFIRE 6 and compared these data to the emission limits in the January 2013 final rule to assess whether those more stringent limits were being achieved in practice. Data is submitted to CEDRI by regulated entities to EPA in order to meet electronic reporting requirements of 40 CFR part 60 subpart DDDDD. These reports include performance tests, CEMS relative accuracy test audits, notifications of compliance status reports, among other items. WebFIRE displays these reports to the public and can be searched by regulatory subpart or boiler process type (e.g., fuel type, boiler size). For existing sources, with the exception of TSM at coal units, all of the compliance data available for the subcategory showed that the units were complying with the more stringent 2013 emission limit. For TSM at coal-fired units, 83 percent of the units (10 of 12) with data were below the more stringent 2013 emission limit. The two units that were not were 12 percent above the 2013 emission limit, but these units were using the emission averaging provision to comply at a common stack. To assess whether the limits were costeffective, the EPA reviewed the control devices currently installed to determine if any cost savings would occur should the less stringent limit be selected. In all of these cases, the controls that were already installed were the same types of controls that would be required to meet either the January 2013 limits or the less stringent recalculated limits and, therefore, no additional costs would be incurred to meet the more stringent limits. There were three additional cases where the January 2013 remanded emission limit was more stringent than the recalculated emission limit, but no recent compliance data were available in these three cases. Since no data were available for PM at Gas 2 units, and TSM at biomass suspension burners or dry biomass stokers, the EPA did not select a beyond-the-floor limit for these three emission limits. In all three of these cases, where we did not have data, the changes are resulting from the revised methodology for limited datasets. The process gas unit is uncontrolled, and the dry biomass stoker and biomass suspension burner both had a multiclone installed. 6 U.S. Environmental Protection Agency. Compliance and Emissions Data Reporting Interface (CEDRI) https://www.epa.gov/electronic-reportingair-emissions/cedri and WebFIRE database https:// www.epa.gov/electronic-reporting-air-emissions/ webfire. E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules Based on the review of compliance data, the EPA selected a beyond-the- 52209 floor level for 10 of the existing source emission limits, as listed in Table 4. TABLE 4—EXISTING SOURCE EMISSION LIMITS BASED ON BEYOND-THE-FLOOR Existing source subcategory limit Discussion HCl-Liquid ........................................................... TSM-Coal ............................................................ TSM-Heavy Liquid .............................................. TSM-Light Liquid ................................................. PM-Dry Biomass Stoker ..................................... CO-Biomass Suspension Burner ........................ CO-Biomass Suspension Grate ......................... CO-Dry Biomass Stoker ..................................... CO-Coal Fluidized Bed with Heat Exchanger .... For new sources, the EPA made a similar comparison to compliance data from new and existing boilers in order to assess whether the limits were achievable. In addition, for PM emission limits at new sources, consistent with the analysis taken during the January 2013 final rule, PM emission limits were compared to the PM limit of 0.03 pound per million British thermal units (lb/ MMBtu) for new biomass boilers in 40 CFR part 60, subparts Db and Dc. Only biomass compliance data were available for new sources, and so the EPA compared both existing and new source compliance data, when available, to the emission limits in the January 2013 final All of the existing units with data available are below the 2013 emission limit. All 10 of the existing units complying with the TSM limit were below the 2013 emission limit. The two existing units with data were both below the 2013 emission limit. The two existing units with data were both below the 2013 emission limit. All six of the existing units with data were below the 2013 limit. All 12 of the existing units with data were below the 2013 limit. All 99 of the existing units with data were below the 2013 limit. All six of the existing units with data were below the 2013 limit. The one existing unit with data was below the 2013 limit. rule. For three of the limits, all of the units with available compliance data were below the more stringent January 2013 emission limit. For the PM limit at dry biomass stokers, and the TSM limit at wet biomass stokers, all of the available new source compliance data were meeting the more stringent January 2013 emission limit. Two of the limits had no new source data available for comparison, but the TSM at coal units had 50 percent of the existing units with data below the January 2013 new source limit, and 9 percent of the coal units were below the new source limit for PM. Both of these cases demonstrate that the limits are technically achievable. There were three cases where the January 2013 remanded new source emission limit was more stringent than the emission limit calculated based on the revised MACT floor calculation methodology, but no recent compliance data were available in these four cases. These were the same three groups mentioned for existing sources, PM at Gas 2 units, and TSM at biomass suspension burners or dry biomass stokers. Due to lack of data, the EPA did not select a beyond-thefloor limit for these three emission limits. For new sources, there were seven emission limits where a beyondthe-floor level was selected, as listed in Table 5. TABLE 5—NEW SOURCE EMISSION LIMITS BASED ON BEYOND-THE-FLOOR New source subcategory limit Discussion TSM-Wet Biomass Stoker .................................. Only one existing and one new wet stoker boiler has TSM compliance data. The new source data is below the 2013 new source limit. Six of the 12 existing units with compliance data are below the 2013 limit for new sources. Of the ones that were above the limit, all of them were above both the 2013 limit and the remanded MACT floor emission limit. No new coal units were identified in recent compliance data. The calculated UPL is identical to the value calculated in the 2013 final rule for existing sources. However, the UPL calculation was less stringent than the new source performance standards (NSPS) limit for new boilers. Additionally, all of the 13 units with PM test data are below the 2013 limit for new sources. Of the seven units with PM test data, three units were below the 2013 emission limits for new sources, including one new dry biomass stoker boiler. Additionally, the UPL calculation was less stringent than the NSPS limit for new boilers. Of the 101 existing units with PM test data, nine units were below the 2013 emission limit for new sources. No new coal units were identified in recent compliance data. All seven of the existing units with data, including one new dry biomass stoker were below the 2013 limit. The one existing unit with data was below the 2013 limit. TSM-Coal ............................................................ PM-Suspension Burner ....................................... PM-Dry Biomass Stoker ..................................... PM-Coal .............................................................. CO-Dry Biomass Stoker ..................................... jbell on DSKJLSW7X2PROD with PROPOSALS2 CO-Coal Fluidized Bed with Heat Exchanger .... C. Revisions to Output-Based Emission Limits The EPA reviewed the output-based emission limits, and revised as necessary, for subcategories and pollutants where the input-based emission limits were revised. There was not a corresponding revision in the output-based emission limit for certain subcategories and pollutants where the input-based emission limit was revised, VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 due to rounding (i.e., the input-based emission limit revision was small enough that performing the outputbased calculations did not result in a different emission limit after rounding to two significant figures). We also updated the output-based emission limit calculations to use data from the current population of best performers, considering the changes to the rankings made in response to the court remands. PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 Specifically, we revised the steam conversion factor (steam Btu out/fuel Btu in) used to calculate the outputbased limits in the units of lb/MMBtu steam output for three subcategories for existing sources: Biomass dutch oven, wet biomass, and coal stoker. We reviewed the corresponding steam conversion factors for new sources, but revisions were not necessary as a result of the new analyses. The memorandum, E:\FR\FM\24AUP2.SGM 24AUP2 52210 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 Alternate Equivalent Output-Based Emission Limits for Boilers and Process Heaters Located at Major Source Facilities—2019 Revision, which is available in the docket for this action, provides details of the output-based emission limit revisions and methodology. D. Proposed Response to the Amended Issue: CO as a Surrogate for Organic HAP On July 29, 2016, the D.C. Circuit remanded to the EPA to address a public comment relating to the potential availability of alternative control technologies which reduce organic HAP without impacting CO emissions. In doing so, the court rejected challengers’ argument that the EPA could not use CO as a surrogate for non-dioxin/furan (D/ F) organic HAP and limited its remand to the Agency’s failure to address evidence in the record on the potential availability of alternative control technologies. The court further noted that ‘‘it is likely’’ that the EPA would be able to adequately explain its use of CO on remand. U.S. Sugar v. EPA, 830 F.3d at 630. It is helpful to provide some background on the EPA’s decision to use CO as a surrogate in the Boiler MACT rule in order to provide the context for the EPA’s action to address the U.S. Sugar court’s remand for explanation. In the preamble to the June 2010 proposal, we presented the rationale for using CO as a surrogate for non-D/F organic HAP emitted from boilers and process heaters. We stated that CO has generally been used as a surrogate for organic HAP because CO is a good indicator of incomplete combustion and organic HAP are products of incomplete combustion. However, based on concerns that CO may not be an appropriate surrogate for D/F because, unlike other organic HAP, D/F can be formed outside the combustion unit, we proposed using CO as a surrogate only for non-D/F organic HAP. For non-D/F organic HAP, we concluded that using CO as a surrogate was a reasonable approach because minimizing CO emissions will result in minimizing non-D/F organic HAP. We stated that, for boilers and process heaters, methods used for the control of CO emissions would be the same methods used to control non-D/F organic HAP emissions. These emission control methods include achieving good combustion or using an oxidation catalyst. Standards limiting emissions of CO will also result in decreases in nonD/F organic HAP emissions (with the additional benefit of decreasing volatile organic compounds (VOC) emissions). VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 Establishing emission limits for specific organic HAP would be impractical and costly. Thus, we concluded that CO, which is less expensive to test for and monitor, is appropriate for use as a surrogate for non-dioxin organic HAP. We stated in the 2010 proposal that we recognized that the level and distribution of organic HAP will vary from unit to unit. For example, the principal organic HAP emitted from coal-fired units is benzene, which accounts for about 20 percent of the organic HAP with formaldehyde accounting for about 4 percent of the organic HAP. Whereas, the principal organic HAP emitted from biomass-fired units is formaldehyde, which accounts for 34 percent of the organic HAP with benzene accounting for about 25 percent of the organic HAP.7 For oil-fired units, formaldehyde is the principal organic HAP, accounting for about 80 percent of the organic HAP. Limiting CO as a surrogate for only non-dioxin organic HAP would eliminate costs associated with speciating numerous compounds. We also stated that CO was preferable because many sources currently have CO continuous emission monitoring systems (CEMS). In the 2013 final rule preamble, as part of the rationale for the 130 ppm CO minimum MACT floor level, we again explained the basis for concluding that CO is an appropriate surrogate. That is, CO is a conservative surrogate for organic HAP because organic HAP emissions are extremely low when sources operate under the good combustion conditions required to achieve low CO levels. There are myriad factors that affect combustion efficiency (CE) and, as a function of CE, CO emissions. As combustion conditions improve and hydrocarbon levels decrease, the larger and easier to combust compounds are oxidized to form smaller compounds that are, in turn, oxidized to form CO and water. As combustion continues, CO is then oxidized to form CO2 and water. Because CO is a difficult to destroy refractory compound (i.e., oxidation of CO to CO2 is the slowest and last step in the oxidation of hydrocarbons), it is a conservative surrogate for destruction of hydrocarbons, including organic HAP. Available control technologies for organic HAP emissions are of two types: Combustion and recovery. The combustion devices include thermal incinerators, catalytic incinerators, 7 Based on emission factors reported on the EPA web page, AP 42, Fifth Edition, Volume 1—Chapter 1: External Combustion Sources, located at https:// www3.epa.gov/ttn/chief/ap42/ch01/final/ c01s01.pdf. PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 flares, and boilers/process heaters. Applicable recovery devices include condensers, adsorbers, and absorbers. The combustion devices are the more commonly applied control devices, since they are capable of high removal (i.e., destruction) efficiencies for almost any type of organic vapor HAP.8 As discussed below, the removal efficiencies of the recovery techniques generally depend on the physical and chemical characteristics of the organic HAP under consideration as well as the emission stream characteristics. Applicability of the control techniques depends on the individual emission stream under consideration. In this case, it would be emission streams from boilers and process heaters. The key emission stream characteristics and HAP characteristics that affect the applicability of each control technique are discussed below. Thermal incinerators use combustion to control a wide variety of continuous organic HAP emission streams. Compared to the other techniques, thermal incineration is broadly applicable; that is, it is much less dependent on HAP characteristics and emission stream characteristics. Destruction efficiencies up to 99 percent or higher are achievable with thermal incineration. Thermal incineration typically is applied to emission streams that are dilute mixtures of organic HAP and air. Catalytic incinerators are similar to thermal incinerators in design and operation except that they employ a catalyst to enhance the reaction rate. Since the catalyst allows the reaction to take place at lower temperatures, significant fuel savings may be possible with catalytic incineration. Catalytic incineration is not as broadly applicable as thermal incineration since performance of catalytic incinerators is more sensitive to pollutant characteristics and process conditions than is thermal incinerator performance. Materials in the emission stream can poison the catalyst and severely affect its performance. Destruction efficiencies of 95 percent of HAP can typically be achieved with catalytic incineration. Flares are commonly used for disposal of waste gases during process upsets and emergencies. They are basically safety devices that are also used to destroy waste emission streams. Flares can be used for controlling almost any organic HAP emission stream. 8 Handbook Control Technologies for Hazardous Air Pollutants, EPA/625/6–91/014, June 1991, Center for Environmental Research Information, Office of Research and Development, U.S. EPA. E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules Boilers or process heaters are used to control emission streams containing organic compounds. These are currently used as control devices for emission streams from several industries (e.g., refinery operations, polymers and resins operations, chemical reactor processes, and distillation operations, etc.). See 40 CFR part 63, subparts JJJ, OOO, and PPP. Typically, off-gases containing organic HAP emissions are controlled in boilers or process heaters and used as supplemental fuel if they have sufficient heating value. When used as emission control devices, boilers or process heaters can provide destruction efficiencies of greater than 98 percent. Carbon adsorption is a recovery (noncombustion) technique commonly employed as a pollution control and/or a solvent recovery technique. It is applied to dilute mixtures of HAP and air. Removal efficiencies of 95 to 99 percent can be achieved using carbon adsorption. Outlet concentrations around 50 parts per million by volume (ppmv) can be routinely achieved with state-of-the-art systems; concentrations as low as 10 to 20 ppmv can be achieved with some compounds. Highly volatile materials (i.e., molecular weight less than about 45) do not adsorb readily on carbon; therefore, adsorption is not typically used for controlling emission streams containing such compounds. Carbon adsorption is also relatively sensitive to emission stream conditions, such as high humidity and temperatures. Absorption is widely used as a raw material and/or a product recovery technique in separation and purification of gaseous streams containing high concentrations of VOC. As an emission control technique, it is much more commonly employed for inorganic vapors than for organic vapors. Using absorption as the primary control technique for organic vapor HAP is subject to several limitations and problems. The suitability of absorption for controlling organic vapor emissions is determined by several factors; most of these factors will depend on the specific HAP in question. For example, the most important factor is the availability of a suitable solvent. The pollutant in question should be readily soluble in the solvent for effective absorption rates. Condensers are widely used as raw material and/or product recovery devices. They are frequently applied as preliminary air pollution control devices for removing VOC contaminants from emission streams prior to other control devices such as incinerators, adsorbers, or absorbers. Condensers are also used by themselves for controlling emission streams containing high VOC VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 concentrations (usually >5,000 ppmv). In these cases, removal efficiencies obtained by condensers can range from 50 to 90 percent although removal efficiencies at the higher end of the scale usually require HAP concentrations of around 10,000 ppmv or greater. Therefore, it is not possible for condensation with water as the coolant to achieve the low outlet concentrations that would be required in HAP control applications. In summary, combustion is the more commonly applied technology for controlling organic HAP since it is capable of high removal efficiencies for organic HAP and its effectiveness does not depend on the makeup of the organic HAP stream or the organic HAP concentration. In fact, the devices regulated by the rule (boilers and process heaters) not only combust fuel for producing steam and/or process heat but serve a dual function in that they also effectively control organic HAP when good combustion conditions are present. Recovery (non-combustion) devices are not applicable on all organic HAP and are not effective on low organic HAP concentration streams. Also, recovery devices’ effectiveness is dependent on an emission stream with a high organic HAP content (≤250 ppmv), compared to the organic HAP content of the emission streams from boilers which are around 1 ppmv for fossil fuels (coal and oil) and around 10 ppmv for biomass.9 Therefore, at the organic HAP levels generated and emitted from a boiler, the recovery (noncombustion) technologies would be ineffective. Furthermore, none of the best performing units employ any addon alternative control device for controlling organic HAP. Many industrial boilers and process heaters employ post combustion controls for PM, acid gases, and/or Hg but these addon controls do not affect emissions of CO or non-dioxin organic HAP. For these reasons, we continue to conclude that the level of CO emissions, which indicates organic HAP reductions achieved through the use of combustion controls, is an appropriate surrogate for controlling organic HAP emissions from boilers and process heaters. E. Proposed Response to the Amended Issue: CO 130 PPM Threshold Emission Limits The D.C. Circuit, on March 16, 2018, issued an opinion in the Boiler MACT reconsideration case, Sierra Club v. 9 Based on emission factors reported on the EPA web page, AP 42, Fifth Edition, Volume 1—Chapter 1: External Combustion Sources, located at https:// www3.epa.gov/ttn/chief/ap42/ch01/final/ c01s01.pdf. PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 52211 EPA, 884 F.3d 1185, which was a petition for review by environmental groups of the 2015 reconsideration of the Boiler MACT rule. The case addressed two issues that were severed from the litigation challenging the 2013 Boiler MACT rule (U.S. Sugar v. EPA): (1) The 130-ppm threshold for CO standards, which, as described above, were established as a surrogate for nondioxin organic HAP and (2) the definitions of periods of startup and shutdown and the applicable work practices to be used during those periods. The court granted the petition as to the CO issue, finding that the EPA had not provided sufficient record support for the CO concentration threshold and remanded for further explanation, but denied the petition on the startup/shutdown issue and upheld the EPA’s approach as consistent with the CAA. The court declined to revisit its opinion in U.S. Sugar, in which the court upheld the use of CO as a surrogate for organic HAP but remanded to the EPA to address whether there are means to reduce organic HAP other than by combustion. Against that backdrop, the court, in its decision in Sierra Club said the question before it was whether, assuming CO is an appropriate surrogate, the EPA’s decision to establish a 130-ppm threshold as the lowest (i.e., most stringent) numeric CO limit was consistent with the requirements of the CAA. Based on a close examination of the record, the court held that the EPA had not sufficiently explained its rationale and questioned EPA’s reliance on data regarding the relationship between formaldehyde and organic HAP that the EPA had previously characterized as unreliable. The court did note that if the EPA made and adequately supported a determination that no further reduction of HAP would occur once CO levels had been reduced to 130 ppm, the threshold would be appropriate and consistent with the CAA. The court noted three specific issues it believed the Agency did not adequately address: (1) The EPA gave no reason why organic HAP emissions could not be further reduced, once CO emissions reach 130 ppm, (2) the EPA relied on formaldehyde data to support its conclusion but elsewhere stated that the same data were not a reliable indicator of organic HAP emissions at very low levels, and (3) the EPA did not adequately explain if there is a non-zero CO level below which organic HAP levels cannot be further reduced, why 130 ppm is the appropriate level. Responses to these three issues are addressed below. E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 52212 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules In the January 31, 2013, final rule, we revised the CO emission limit for several subcategories, both new and existing, to reflect a CO level that, we stated, is consistent with MACT for organic HAP reduction. The revision was brought about by several commenters who recommended that the EPA evaluate a minimum CO standard (i.e., 100 ppm corrected to 7-percent oxygen 10) to serve as a lower bound surrogate for organic HAP. The commenters also provided data and information to support such a standard and noted that the EPA has taken a similar approach in other emission standards under CAA section 112. See 40 CFR part 63, subpart EEE (NESHAP for Hazardous Waste Combustors). In the preamble to the 2013 final rule, we stated that we evaluated whether there is a minimum CO level for boilers and process heaters below which there is no further benefit in organic HAP reduction/destruction. Specifically, we evaluated the relationship between CO and formaldehyde using the available data obtained during the rulemaking. Formaldehyde was selected as the basis of the organic HAP comparison because it is the most prevalent organic HAP in the emission database and many paired tests existed for boilers and process heaters for CO and formaldehyde and because formaldehyde was the only organic HAP for which we had such data. The paired data show decreasing formaldehyde emissions with decreasing CO emissions down to CO levels around 300 ppm (with formaldehyde emissions down to less than 1 ppm), supporting the selection of CO as a surrogate for organic HAP emissions. A slight increase in formaldehyde emissions, to between 1 and 2 ppm, was observed at CO levels below around 200 ppm, suggesting a breakdown in the CO-formaldehyde relationship at low CO concentrations. At levels lower than 150 ppm, the mean levels of formaldehyde appeared to increase, as does the overall maximum value of and variability in formaldehyde emissions. However, at that time, we were not aware of any reason why formaldehyde concentrations would increase as CO concentrations continue to decrease, indicating improved combustion conditions. Our thinking at the time was that imprecise formaldehyde measurements at low concentrations (i.e., 1–2 ppm) may have accounted for this slight increase in 10 The CO emission standards in the 2013 final rule are corrected to 3-percent oxygen. The 130 ppm CO standards in the 2013 final rule is equivalent to 100 ppm corrected to 7-percent oxygen. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 formaldehyde emissions observed at CO levels below 130 ppm. In the preamble of the 2013 final rule, we stated, ‘‘Based on this, we do not believe that such measurements are sufficiently reliable to use as a basis for establishing an emissions limit.’’ See 78 FR 7145. In that statement, we were referring to the formaldehyde measurements and, thus, to the decision to set a CO standard instead of a formaldehyde standard. Based on that analysis, we promulgated a minimum MACT floor level for CO of 130 ppm corrected to 3-percent oxygen (which is equivalent to 100 ppm corrected to 7percent oxygen). We noted this was the same approach used to establish the CO emission limit of 100 ppm corrected to 7-percent oxygen for the Burning of Hazardous Waste in Boilers and Industrial Furnaces final rule (56 FR 7134, February 21, 1991). In that rulemaking, the EPA chose the 100-ppm (corrected to 7-percent oxygen) limit because the research indicated that while CO was a good surrogate for the destruction of organic HAP, the validity of that surrogacy was questionable at CO levels of approximately 400 ppm and below. Based on the EPA’s authority under the Resource Conservation and Recovery Act to establish standards that are protective of human health and the environment, the Agency established the 100-ppm standard. The EPA later established the 100-ppm corrected to 7percent oxygen standard as the MACT standard for hazardous waste combustors (see 70 FR 59462) and explained why that standard was an appropriate floor (see 69 FR at 21282). The trend that our CO—formaldehyde data present has also been observed in a study 11 done on polycyclic aromatic hydrocarbons (PAH) emissions from coal combustion. PAH constitute a group of organic HAP. The study presents a graph of PAH vs. excess oxygen 12 which shows that at the lowest percentage of excess oxygen (5 percent), the highest PAH amount (0.25 ppm) is measured and shows minimum PAH emissions (0.02 ppm) at 20-percent excess oxygen. The graph further shows that as the excess oxygen level increases above 20 percent, higher PAH emissions 11 Organic Atmospheric Pollutants: Polycyclic Hydrocarbons from Coal Atmospheric Fluidised Bed Combustion (AFBC), A.M Mastral, M.S. Callen, R. Murillo, and T. Garcia, Instituto de Carboquimica, 1999. 12 Excess oxygen, or excess air, is commonly used to define combustion. The excess oxygen is the amount of oxygen in the incoming air not used during combustion. Inadequate excess oxygen results in unburned combustibles (fuel and CO), while too much excess oxygen results in increased flue gas flow and decreased temperature and residence time for combustion. PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 (about 0.06 ppm at 40 percent excess air) are observed. The study does not present corresponding CO values. However, the study does provide information showing that CO emissions continue to decrease with increasing excess oxygen levels above 20 percent, as indicated by the increased combustion efficiencies reported in the study for excess oxygen over the range of 5 to 40 percent. Combustion efficiency (CE) is a measure of the completeness of oxidation of all fuel (organic) compounds and is determine by the CE Formula: CE = [CO2/(CO2 + CO)] × 100.13 Thus, CE increases with decreasing CO levels. The PAH study does provide a possible explanation for this phenomenon. In order to assess the PAH emissions as a function of combustion variables, the first aim of the study was to reach maximum CE. The study stated that ‘‘it can be assumed that the emissions due to bad combustion have practically been eliminated, and so the data obtained will be due to the combustion process.’’ The study states that at the lowest percentages of excess oxygen, the interaction between oxygen and radicals should be less favored and, as a result, the PAH amount would be higher. At the highest percentages of excess oxygen possible, interaction with PAH seemed to be minimized due to the higher gas velocities shortening the contact resulting in increasing PAH emissions. Furthermore, the EPA’s Office of Research and Development (ORD), in support of the NESHAP from Coal- and Oil-Fired Electric Utility Steam Generating Units (also known as the Mercury and Air Toxics Standards or MATS), conducted a series of tests in the Agency’s Multipollutant Control Research Facility (MPCRF). As part of these tests, potential surrogate relationships were examined for various non-D/F organic HAP. The objective of the testing program was to collect selected HAP emission data while firing coals under varied test conditions and evaluate relationships between those concentrations and other process concentrations and/or conditions. One of the principal objectives was to measure concentrations of non-D/F organic HAP and compare to the emission of candidate surrogates (e.g., CO, total hydrocarbons, etc.) 14 Several organic HAP, discussed below and 13 CE formula and calculator, https:// ncalculators.com/environmental/combustionefficiency-calculator.htm. 14 Surrogacy Testing in the MPCRF, Prepared for U.S. EPA, Prepared by ARCADIS, March 30, 2011. See Docket ID Item No. EPA–HQ–OAR–2002–0058– 3942. E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules presented as figures in the study’s final report, were quantified from multiple tests with CO concentrations and show a similar trend. Figure 4–16 of the MPCRF study shows the concentration of phenol, an organic HAP, plotted against concentration of CO. CO concentrations ranged from 40 to 140 ppm, at 7-percent oxygen, with phenol concentrations ranging from 0.6 parts per billion (ppb) at 40 ppm CO to 1 ppb at 140-ppm CO with the lowest phenol concentration (0.5 ppb) measured at 95-ppm CO (120ppm CO at 3-percent oxygen). The MPCRF study also examined formaldehyde emissions against CO concentrations. The five data points (Figure 4–17 of the study) are all for CO concentrations below 70 ppm with the lowest formaldehyde emissions (10 ppb) measured at 70-ppm CO and with higher formaldehyde emissions (57 ppb) measured at a lower CO level of 40-ppm CO. In addition, the MPCRF study shows similar results for chloroform (another organic HAP). The five data points (Figure 4–24 of the study) show chloroform emissions of 0.038 ppb at 170-ppm CO at 3-percent oxygen, 0.025 ppb chloroform at 130-ppm CO at 3percent oxygen, and 0.054 ppb chloroform at 40-ppm CO at 3-percent oxygen. The MPCRF does not present any explanation on why these trends were observed. One of the goals of the MPCRF testing was to determine or demonstrate a relationship between concentrations of organic compounds and combustion conditions. However, due to low emission levels, non-detects, and other complexities, the key conclusion drawn was that the testing did not disprove an expected relationship between organic concentrations and combustion conditions. There are myriad factors that affect CE and, as a function of CE, CO emissions. As combustion conditions improve and hydrocarbon levels decrease, the larger and easier to combust compounds are oxidized to form smaller compounds that are, in turn, oxidized to form CO and water. As combustion continues, CO is then oxidized to form CO2 and water. Because CO is a difficult to destroy refractory compound (i.e., oxidation of CO to CO2 is the slowest and last step in the oxidation of hydrocarbons), it has been considered a conservative surrogate for destruction of hydrocarbons, including organic HAP. Neither the PAH study nor the MPCRF study provide an explanation for the phenomenon observed in these studies. In trying to explain why this VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 phenomenon occurs, we know that combustion is the chemical reaction of oxygen with combustible compounds (e.g., organics) and that time, temperature, and turbulence impact the speed and completeness of the combustion reaction. For complete combustion, the oxygen must come into intimate contact with the combustible molecule at sufficient temperature, and for a sufficient length of time, in order to complete the reaction. Two factors that affect reaction rates are the concentration of the reactants (oxygen and organic HAP) and the temperature of the reactants. Every combustible substance has a minimum ignition temperature, which must be attained or exceeded, in the presence of oxygen, if combustion is to ensue under the given conditions. Lower concentrations will produce a decrease in the rate of reaction and a decrease in the temperature will decrease rate of reaction. As more ambient temperature combustion air (oxygen) is added, the concentration and temperature of the reactant (organic HAP) is reduced. Thus, a potential explanation is that with the increased combustion air (oxygen), the resulting increased turbulence, while providing increased mixing, can result in more organic molecules being forced near the furnace walls, which are cold compared to the combustion zone. This can essentially slow down or quench the combustion reactions by cooling the molecules of the organic compounds to below their minimum ignition temperature. Thus, those organic HAP molecules would not be combusted and would be emitted unchanged. Any action having the effect of decreasing the reaction rate of the organic HAP will consequently result in less organic HAP being combusted and, thus, higher organic HAP emissions being observed and appear to be an increase, at higher excess oxygen (and lower CO emissions) levels. The range of the formaldehyde measurements for the reported paired formaldehyde-CO emissions data for the 97 emission units is 0.00009 ppm (0.09 ppb) to 2.0 ppm. The mathematical average of the corresponding CO emissions from the best performing 12 percent of units, identified as those units with the lowest formaldehyde emissions, is 137 ppm. At the time of the 2013 rulemaking, we observed that reducing CO emissions also resulted in a reduction of organic HAP emissions until a leveling off in organic HAP reduction is reached after which further reduction of CO levels appeared to result in higher levels of organic HAP emitted. Our determination that setting a CO standard PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 52213 below a CO level of 130 ppm would result in no additional organic HAP reduction is supported by both the independent PAH emission study and the MPCRF study which both show similar trends. That is, organic HAP levels decreased with decreasing CO levels until a leveling off and trending upward with further decreasing CO levels. Also, based on the level of the organic HAP emissions measured in the two studies, we do not consider the formaldehyde data used in our establishment of the 130 ppm CO standard to have been imprecise and, thus, unreliable. The formaldehyde data measured at CO levels below 130 ppm reflect the variability (scatter) of organic HAP emissions when each data point is from a different unit. Whereas, the organic HAP emission results presented in the two studies, which were measured at similar low concentrations, are from tests conducted on a single unit at varying CO levels. The seven subcategories with the 130 ppm CO level in the 2013 final rule are: (1) Pulverized Coal Boilers; (2) Coal Stokers; (3) Coal Fluidized Bed; (4) Heavy Liquid Fuel; (5) Light Liquid Fuel; (6) Non-Continental Liquid; and (7) Process Gas. Based on our review of the data in 2013, we established that a CO emission level of 130 ppm represented MACT for controlling organic HAP emissions for units in the six subcategories. Based on additional information obtained during and after the rulemaking, as discussed above, we reaffirm our conclusion that a 130-ppm CO concentration threshold represents MACT for organic HAP for the six subcategories. IV. Results and Proposed Decisions A. What are the resulting changes to emission limits? Based on all of the revisions made to address the remand related to ranking and assessing co-fired units in the MACT floor calculations, the changes made for UPL calculations for small datasets, and the decisions to propose certain limits as beyond-the-floor limits, there are 34 different emission limits that we are proposing to change. The detailed list of revisions to unit rankings and revised MACT floor calculations are presented in the docketed memorandum, Revised MACT Floor Analysis (2019) for the Industrial, Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source. Of these 34 emission limits, 28 of the limits are more stringent than the corresponding limits in the 2013 final rule. Six of the E:\FR\FM\24AUP2.SGM 24AUP2 52214 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules limits are modestly less stringent, with no more than a 25-percent increase. The proposed and corresponding current limits are shown in Table 6. TABLE 6—SUMMARY OF CHANGES TO EMISSION LIMITS IN THE PROPOSED ACTION Subcategory Pollutant New-Solid ............................................................................................................ New-Dry Biomass Stoker .................................................................................... New-Biomass Fluidized Bed ............................................................................... New-Biomass Fluidized Bed ............................................................................... New-Biomass Suspension Burner ....................................................................... New-Biomass Suspension Burner ....................................................................... New-Biomass Hybrid Suspension Grate ............................................................. New-Biomass Dutch Oven/Pile Burner ............................................................... New-Biomass Fuel Cell ....................................................................................... New-Wet Biomass Stoker ................................................................................... New-Wet Biomass Stoker ................................................................................... New-Liquid ........................................................................................................... New-Heavy Liquid ............................................................................................... New-Process Gas ................................................................................................ Existing-Solid ....................................................................................................... Existing-Solid ....................................................................................................... Existing-Coal ........................................................................................................ Existing-Coal Stoker ............................................................................................ Existing-Dry Biomass Stoker ............................................................................... Existing-Wet Biomass Stoker .............................................................................. Existing-Wet Biomass Stoker .............................................................................. Existing-Biomass Fluidized Bed .......................................................................... Existing-Biomass Fluidized Bed .......................................................................... Existing-Biomass Suspension Burners ............................................................... Existing-Biomass Dutch Oven/Pile Burner .......................................................... Existing-Liquid ..................................................................................................... Existing-Heavy Liquid .......................................................................................... Existing-Non-Continental Liquid .......................................................................... Existing-Process Gas .......................................................................................... HCl ................. TSM8 ............. CO ................. PM (TSM) ...... CO ................. TSM ............... CO ................. PM ................. PM ................. CO ................. PM ................. HCl ................. PM (TSM) ...... PM ................. HCl ................. Hg .................. PM ................. CO ................. TSM ............... CO ................. PM (TSM) ...... CO ................. PM (TSM) ...... PM (TSM) ...... PM ................. Hg .................. PM ................. PM ................. PM ................. jbell on DSKJLSW7X2PROD with PROPOSALS2 The EPA requests comment on the revisions to the emission limits in light of the changes the EPA has proposed in response to the remand. Broader comments with respect to the UPL calculation methodology will not be considered within the scope of this rulemaking. The EPA will only consider data that is already available in the rulemaking record. The EPA also requests comments on its determination of beyond-the-floor emission limits for certain subcategories. The emission reduction impacts associated with these changes to the MACT floor emission limits are discussed in the docketed memorandum Revised (2019) Methodology for Estimating Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 Emission Standards for Hazardous Air Pollutants. B. What compliance dates are we proposing? The EPA is proposing that facilities have up to 3 years after the effective date of the final rule to comply with the new emissions limits in the final rule. Before this date, facilities must continue to comply with the rule as it was finalized in 2015. This allowance is being made considering that some facilities may require additional add-on controls or monitoring equipment to be designed, purchased, and installed in order to meet the more stringent emission limits, or to modify the method of compliance based on the changes in emission limits. In addition, PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 Current emission limit (lb/MMBtu of heat input or ppm at 3-percent oxygen for CO) 9.8E–03 1.3E–02 3.7E–02 1.1E–01 5.1E–02 2.2E–02 4.0E–03 230 (8.3E–05) 2,400 6.5E–03 1,100 3.2E–03 2.0E–02 620 0.03 4.4E–04 (7.5E–05) 6.7E–03 2.2E–02 5.7E–06 4.0E–02 160 4.0E–03 1,500 (2.4E–04) 470 (1.2E–03) (6.5E–03) 2.8E–01 2.0E–06 6.2E–02 2.7E–01 6.7E–03 Proposed emission limit (lb/MMBtu of heat input or ppm at 3-percent oxygen for CO) 4.1E–03 1.9E–03 3.4E–02 2.1E–02 4.1E–02 3.0E–04 5.0E–03 130 (8.4E–06) 220 8.0E–03 180 2.5E–03 1.1E–02 590 0.013 7.0E–05 (6.4E–06) 7.3E–03 2.0E–02 5.4E–06 3.9E–02 150 5.0E–03 1,100 (2.0E–04) 210 (6.4E–05) (8.0E–03) 1.8E–01 7.3E–07 5.9E–02 2.2E–01 7.3E–03 units will require lead time to prepare and execute their testing plans to demonstrate compliance with the updated emission limits and to update reports to incorporate the revised emission limits. The EPA requests comment on this time frame. C. What other actions are we proposing? We are proposing several technical corrections. These amendments are being proposed to correct inadvertent errors that were promulgated in the final rule. We are soliciting comment only on whether the proposed changes provide the intended accuracy, clarity, and consistency. These proposed changes are described in Table 7 of this preamble. We request comment on all these proposed changes. E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules 52215 TABLE 7—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD Section of subpart DDDDD Description of proposed correction 40 CFR 63.7500(a) .............. 40 CFR 63.7521(c)(1)(ii) 40 CFR 63.7530(b)(4)(iii) Revise this paragraph to remove the comma after ‘‘paragraphs (b).’’ Revise this paragraph to remove the requirement to collect samples during the test period at 1-hour intervals. Revise this paragraph to remove the sentence regarding establishing the pH operating limit because establishing the pH operating limit is not required for a PM wet scrubber. Revise this paragraph to clarify that ‘‘certify’’ is intended to apply only to PM CEMS, not PM continuous parameter monitoring systems (CPMS) because PM CPMS do not have a performance specification. Revise the definition of ‘‘Other gas 1 fuel’’ to clarify that it is the maximum Hg concentration of 40 micrograms/ cubic meter of gas. Add definition of ‘‘12-month rolling average’’ to clarify that the previous 12 months must be consecutive but not necessarily continuous. Revise paragraph (4) of definition ‘‘Steam output’’ to correct ‘‘heaters’’ to ‘‘headers.’’ Revise the output limit in item 8.a to correct for a rounding error, the value is now 4.3E–01 lb per MMBtu instead of 4.2E–01 lb per MMBtu. Revise footnote ‘‘b’’ to clarify that when multiple performance tests are conducted, the maximum operating load is the lower of the maximum values established during the performance tests. Revise item 8.d to clarify that the correct equations to use are Equations 7, 8, and/or 9 in 40 CFR 63.7530. 40 CFR 63.7540(a)(9) 40 CFR 63.7575 ................... Table 1 to subpart DDDDD Table 7 to subpart DDDDD Table 8 to subpart DDDDD V. Summary of Cost, Environmental, and Economic Impacts A. What are the affected sources? As mentioned previously, this rule affects a wide range of facilities in the ICI sector that are located at major sources of HAP and have a boiler or process heater as defined in the final rule. The 2013 Emission Database for Boilers and Process Heaters estimated there were approximately 14,000 existing boilers and process heaters currently operating at 1,702 different facilities that are major sources of HAP and subject to the Boiler MACT. The vast majority of these combustion units (nearly 12,000 units) were gas-fired and in the Gas 1 subcategory, which are subject to the rule but are not subject to numeric emission limits. Another 472 units were small or limited use and were also not subject to numeric emission limits. By contrast, the EPA has reviewed compliance data submitted to CEDRI and WebFIRE and the trade association Council of Industrial Boilers, which had provided input on units that had shutdown or switched to natural gas fuel as part of its compliance strategy. The EPA then compiled an updated estimate of units that are subject to emission limits. These data show 533 existing boilers and process heaters, of which 443 remain operational and belong in one of the subcategories that are subject to numeric emission limits. This count excludes any boilers that are no longer operational, boilers that have refueled and switched to the natural gas subcategory and are, therefore, no longer impacted by changes to emission limits, or boilers that are classified as small or limited use. For new sources, the EPA had projected new sources anticipated to be built by 2015 from a baseline year of 2008.15 While the projections had anticipated correctly that the only new units subject to emission limits would be new large biomass units, the actual number of new units is significantly lower than projected in the January 2013 final rule. The CEDRI and WebFIRE compliance data provided updates on eight new biomass units that are subject to emission limits and reporting compliance data. Since new units have had to comply since April 2013, these eight units reflect a new unit rate of 1.3 new units per year during the 6-year period of April 2013 through April 2019. Using these new source data, the EPA estimates that, four more biomass boilers or process heaters are expected to be constructed over the next 3 years. As such, 12 new boilers and process heaters are estimated to be affected by the proposed amendments. Table 8 presents a summary table comparing the number of existing and new affected sources, by subcategory. The counts exclude small or limited use units. jbell on DSKJLSW7X2PROD with PROPOSALS2 TABLE 8—SUMMARY OF CHANGES TO NUMBER OF AFFECTED SOURCES Subcategory Estimate of sources in 2013 final rule Existing-Biomass ............................................... Existing-Coal ...................................................... Existing-Heavy Liquid ........................................ Existing-Light Liquid .......................................... Existing-Non-Continental Liquid ........................ Existing-Process Gas ........................................ New-Biomass ..................................................... New-Coal ........................................................... New-Heavy Liquid ............................................. New-Light Liquid ................................................ New-Non-Continental Liquid .............................. New-Process Gas .............................................. 481 .................................................................... 606 .................................................................... 291 .................................................................... 260 .................................................................... 19 ...................................................................... 78 ...................................................................... 78 (projected online by 2015) .......................... 0 ........................................................................ 0 ........................................................................ 0 ........................................................................ 0 ........................................................................ 0 ........................................................................ 285. 124. 6. 24. 5. 0. 8 (actual) + 4 (projected). 0. 0. 0. 0. 0. Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants—Major Source. November 2011. Docket ID Item No. EPA– HQ–OAR–2002–0058–3388. 15 See docketed memorandum: Revised New Unit Analysis Industrial, Commercial, and Institutional VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 Estimate of sources in 2019 proposal E:\FR\FM\24AUP2.SGM 24AUP2 52216 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules B. What are the air quality impacts? Table 9 of this preamble illustrates, for each basic fuel subcategory, the incremental emissions reductions that would be achieved by the proposed amendments. The reductions are all additional to the reductions accounted for in the January 2013 final rule for both new and existing sources. Nationwide emissions of selected HAP (i.e., HCl, hydrogen fluoride, Hg, metals) would be reduced by an additional 37.35 tpy as compared to the estimates in the January 2013 final rule. This additional decrease is due mainly to changes to certain emission limits that are anticipated to achieve additional reductions. The proposed amendments are expected to result in an additional 34 tpy of reductions in HCl emissions. The proposed amendments are also expected to have a modest effect on Hg, with an estimated additional reduction of 3.96 lbs per year. Emissions of filterable PM would decrease by 333 tpy, of which 251 tpy is PM2.5, due to the proposed amendments. Emissions of non-Hg metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium) would decrease by 2.3 tpy. In addition, the proposed amendments are estimated to result in an additional 393 tpy of reductions in SO2 emissions. A discussion of the methodology used to estimate emissions, emissions reductions, and incremental emission reductions is presented in the memorandum, Revised (2019) Methodology for Estimating Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, which is available in the docket for this action. TABLE 9—SUMMARY OF TOTAL EMISSIONS REDUCTIONS FOR THE PROPOSED RULE [Tons/Yr] Source Subcategory Exiting Units ...................................... Coal .................................................. Biomass ............................................ Biomass ............................................ New Units ......................................... 1 Antimony, HCl Non-Hg metals 1 PM 9.8 14.5 9.8 0 333 0 Hg 0 2.3 0 1.88E–03 1.79E–04 0 arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. C. What are the cost impacts? We estimated the total capital costs of the proposed amendments to be about $83 million and the total annualized costs to be about $22 million in 2016 dollars. The total capital and annual costs include costs for control devices, testing, and monitoring associated with the changes to the emission limits. These costs are incremental to the costs presented in the January 2013 final rule in the sense that they show where units with compliance data must install addon controls or modify compliance strategies in order to meet the more stringent limits in this proposal. Table 10 of this preamble shows the total capital and annual cost impacts of the proposed rule for each subcategory. The cost methodology and results are documented in the memorandum, Revised (2019) Methodology for Estimating Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, which is available in the docket for this action. TABLE 10—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES FOR THE PROPOSED RULE [2016$] Source Subcategory New Units ......................................... Coal .................................................. Biomass ............................................ Solid units (all biomass) Existing Units jbell on DSKJLSW7X2PROD with PROPOSALS2 Estimated/ projected number of affected units In addition, another way to present compliance costs is the PV. A PV is an estimate of costs that is a discounted stream of the annualized costs for the proposal calculated for the present day. The PV in 2016 of the costs is $103.7 million at a discount rate of 7 percent and $128.1 million at 3 percent. Calculated as an EAV, which is consistent with the PV of costs in 2016, the costs are $17.4 million at a discount rate of 7 percent and $18.3 million at a VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 2 26 5 discount rate of 3 percent. These estimates are also in 2016 dollars. More information on the PV and EAV estimates can be found in the RIA for this proposal that is in the docket for this action. D. What are the secondary impacts? The EPA estimated the additional water usage that would result from installing wet scrubbers to meet the proposed amended emission limits for PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 Capital costs (106 $) 0.803 81.1 0.952 Testing and monitoring annualized costs (106 $/yr) 0.006 0.267 0.017 Annualized cost (106 $/yr) 0.327 20.5 0.653 HCl would be 0.64 million gallons per year for new and existing sources compared to the current baseline. In addition to the increased water usage, an additional 0.27 million gallons per year of wastewater would be produced for new and existing sources. The annual costs of treating the additional wastewater are approximately $1,830. These additional costs are accounted for in the control cost estimates. E:\FR\FM\24AUP2.SGM 24AUP2 52217 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules The EPA estimated the additional solid waste that would result due to the proposed amendments to be 1,550 tpy for new and existing sources. Solid waste is generated from flyash and dust captured in fabric filters and electrostatic precipitators (ESP) installed for PM and Hg controls as well as from spent materials from wet scrubbers and sorbent injection systems installed for additional HCl controls. The costs of handling the additional solid waste generated are $74,100. These costs are also accounted for in the control costs estimates. The EPA estimated the proposed amendments would result in an increase of about 29.5 million kilowatts per year in national energy usage from the electricity required to operate control devices, such as wet scrubbers, ESPs, and fabric filters which are expected to be installed to meet the proposed rule. This energy requirement is estimated to result in an increase of approximately 17,740 tpy CO2 based on emissions related to additional energy consumption. A discussion of the methodology used to estimate impacts is presented in the Revised (2019) Methodology for Estimating Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants, which is available in the docket for this action. E. What are the economic impacts? The EPA conducted an economic impact analysis for this proposal, as detailed in the Regulatory Impact Analysis for the Proposed ICI Boilers NESHAP Reconsideration, which is available in the docket for this action. The economic impacts of the proposal are calculated as the percentage of total annualized costs incurred by affected parent owners to their annual revenues. This ratio of total annualized costs to annual revenues provides a measure of the direct economic impact to parent owners of affected facilities while presuming no passthrough of costs to consumers of output produced by these facilities. We estimate that none of the 26 parent owners affected by this proposal will incur total annualized costs of 0.70 percent or greater of their revenues. Thus, these economic impacts are quite low for the affected companies and the multiple affected industries, and consumers of affected output should experience minimal price changes. F. What are the benefits? The EPA reports the estimated impact on health benefits from changes in PM2.5 and SO2 emissions. The estimated health co-benefits are the monetized value of the human health benefits among populations exposed to changes in PM2.5. These benefits are co-benefits in this analysis since these pollutants are not targeted for control by this proposal. This rule is expected to alter the emissions of PM2.5 (and SO2). Due to the small change in emissions expected, we used the ‘‘benefit per ton’’ (BPT) approach to estimate the benefits of this rulemaking. The EPA has applied this approach in several previous RIAs 16 in which the economic value of human health impacts are derived at the national level based on previously established source-receptor relationships from photochemical air quality modeling.17 These BPT estimates provide the total monetized human health benefits (the sum of premature mortality and premature morbidity) of reducing 1 ton of PM2.5 (or PM2.5 precursor such as nitrogen oxide or SO2) from a specified source. Specifically, in this analysis, we multiplied the estimates from the ‘‘Industrial Point Sources’’ sector by the corresponding emission reductions. This assumes that the emissions reductions from this proposed rule for industrial boilers scale linearly with the BPT Industrial Point Sources sector. The method used to derive these estimates is described in the Technical Support Document on estimating the BPT of reducing PM2.5 and its precursors from 17 sectors.18 One limitation of using the BPT approach is an inability to provide estimates of the health benefits associated with exposure to HAP (HCl, for example), CO, nitrogen dioxide, or ozone. The photochemical modeled emissions of the industrial point source sector-attributable PM2.5 concentrations used to derive the BPT values may not match the change in air quality resulting from the emissions controls. The PM2.5 emission reductions resulting from this rule are approximately 0.4 percent of the PM2.5 annual emissions and 0.04 percent of the SO2 emissions attributable to the BPT Industrial Point Sources. For this reason, the health cobenefits reported in Table 11 may be larger, or smaller, than those realized through this rule. We are taking comment on the modeling assumptions behind the benefits analysis results mentioned above as well as the utility of performing full-form (i.e., full-scale) photochemical modeling for the final rule. Table 11 summarizes the monetized PM-related health benefits per ton or reducing precursor pollutant emissions, using discount rates of 3 percent and 7 percent. TABLE 11—ESTIMATED PM2.5-RELATED BENEFITS PER TON OF PROPOSED ICI BOILERS AND PROCESS HEATERS MACT RECONSIDERATION Epidemiologic study used to quantify PM-related premature deaths Krewski et al. (2009) Pollutant BPT (3-percent discount rate) jbell on DSKJLSW7X2PROD with PROPOSALS2 PM2.5 ........................................................................................ SO2 .......................................................................................... 16 U.S. EPA. Regulatory Impact Analysis for the Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP Approvals for 22 States. June 2011; Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards, December 2011; VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 $330,000 52,000 Lepeule et al. (2012) BPT (7-percent discount rate) $300,000 47,000 and Regulatory Impact Analysis for the Particulate Matter National Ambient Air Quality Standards; December 2012. 17 Fann N, Fulcher CM, Hubbell BJ. The influence of location, source, and emission type in estimates of the human health benefits of reducing a ton of PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 BPT (3-percent discount rate) $790,000 120,000 BPT (7-percent discount rate) $690,000 100,000 air pollution. Air Qual Atmos Health. 2009;2(3):169–176. doi:10.1007/s11869–009–0044– 0. 18 U.S. EPA, Technical Support Document. Estimating the Benefit per Ton of Reducing PM2.5 Precursors from 17 Sectors. February 2018. E:\FR\FM\24AUP2.SGM 24AUP2 52218 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules Table 12 summarizes the range of estimated benefits by pollutant for the two BPT estimates at discount rates of 3 percent and 7 percent. TABLE 12—ESTIMATED PM2.5-RELATED HEALTH BENEFITS OF PROPOSED ICI BOILERS AND PROCESS HEATERS MACT RECONSIDERATION Epidemiologic study used to quantify PM and SO2-related premature deaths Krewski et al. (2009) Benefits (millions of 2016$, 3-percent discount rate) Benefits (millions of 2016$, 7-percent discount rate) Benefits (millions of 2016$, 3-percent discount rate) Benefits (millions of 2016$, 7-percent discount rate) PM2.5 ........................................................................................ SO2 .......................................................................................... $84 21 $76 19 $200 49 $170 40 Total .................................................................................. 110 95 250 210 Pollutant All BPT estimates have inherent limitations. Specifically, all nationalaverage BPT estimates reflect the geographic distribution of the modeled emissions, which may not exactly match the emission reductions in this rulemaking, and they may not reflect local variability in population density, meteorology, exposure, baseline health incidence rates, or other local factors for any specific location. The photochemical modeled emissions of the industrial point source sectorattributable PM2.5 concentrations used to derive the BPT values may not match well the change in air quality resulting from the emissions controls. For this reason, the health benefits reported here may be larger, or smaller, than those realized by this rule. There are also climate disbenefits from the increase in CO2 emissions that result from the increase in national energy use from control device operation. The disbenefits are $0.09 million at a 3-percent discount rate and $0.01 million at a 7-percent discount rate. These calculations reflect the domestic social cost of carbon for CO2 for 2025, the year for which benefits are estimated that is an approximation for 2023, the year of full rule compliance. These disbenefits are included in the estimates of benefits and net benefits for this proposal. The benefit analysis for this proposal is detailed in the Regulatory Impact Analysis for the Proposed ICI Boilers and Process Heaters NESHAP Reconsideration, which is available in the docket for this action. jbell on DSKJLSW7X2PROD with PROPOSALS2 Lepeule et al. (2012) VI. Request for Comments The EPA is seeking comments on the issues raised in this proposal. It will not respond to comments addressing any other issues. Specifically, the EPA is seeking comments on the revised MACT floor emission limit calculations, VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 including any comments or corrections to the underlying data used to compute those emission limits, the selection of beyond-the-floor limits for certain subcategories. The EPA is also seeking input on the inventory of units used to quantify the impacts of these proposed amendments, which relied on real compliance data submitted to CEDRI and WebFIRE through April 2019, and the methodology used to quantify the impacts analysis discussed in section V of this preamble. The EPA is also seeking comments on the accuracy of the control technology assessment and/ or whether there are other compliance options available to meet the proposed revised emissions limits. Finally, we request comment on the Agency’s approach for using a Benefit per-Ton value to quantify benefits as well as the utility of performing full-form modeling for the final rule. The current version of this regulation contains language which details how facilities that seek to monitor CO2 in lieu of oxygen as part of their CEMS used to demonstrate compliance with the CO emission limits in this subpart must have this approach approved as an alternative method before doing so. The EPA is seeking comment on replacing the requirement to have approval of an alternative test method with a required methodology to be followed when monitoring CO2 in lieu of oxygen as the diluent for CO which would account for any changes in CO2 emission levels caused by a control device, etc. Additionally, the EPA believes it is appropriate to expand this language to the monitoring of all pollutants when CO2 is used as the diluent and seeks comment on this as well. Finally, in the course of reviewing the monitoring language under 40 CFR part 63, subpart DDDDD, the EPA is proposing to remove several requirements for the continuous monitoring of moisture and flow which PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 were found to be unnecessary. We also seek comment on these revisions. A draft of the language we would propose to accomplish these revisions is included in the docket. VII. 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 OMB for review. Any changes made in response to OMB recommendations have been documented in the docket. The RIA for the ICI Boilers NESHAP Reconsideration contains the estimated costs, benefits, and other impacts associated with this action, and it is available in the docket. B. Executive Order 13771: Reducing Regulations and Controlling Regulatory Costs This action is expected to be an Executive Order 13771 regulatory action. Details on the estimated costs of this proposed rule can be found in the EPA’s analysis of the potential costs and benefits associated with this action, which is the RIA for this proposal. C. Paperwork Reduction Act (PRA) The new information collection activities imposed by this proposed rule have been submitted for approval to OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2028.10. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. E:\FR\FM\24AUP2.SGM 24AUP2 jbell on DSKJLSW7X2PROD with PROPOSALS2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions (40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. The proposed amendments change several emission limits as part of the EPA’s response to the remand granted on December 23, 2016, by the D.C. Circuit. The changes result in more stringent emission limits in some cases, which is expected to require additional recordkeeping and reporting burden. This increase is a result of additional monitoring and control devices anticipated to be installed to comply with the more stringent emission limits in the proposed amendments. With additional control devices, comes additional control device parametric monitoring, or in the case of CO, continuous emissions monitoring, and the associated records of that monitoring that must be maintained onsite and reported. Over the next 3 years, approximately 25 respondents operating existing large solid fuel-fired boilers and three respondents operating new solid fuel-fired boilers will be impacted by the new requirements under the standard as a result of these amendments. In addition to the costs to install and maintain records of additional monitoring equipment, the ICR details other additional record keeping and reporting burden changing records associated with adjusting operating parameter limit values, modifying monitoring plans, and familiarizing themselves with the changes in the proposed amendments. Respondents/affected entities: Owners or operators of ICI boilers and process heaters. Respondent’s obligation to respond: Mandatory, 40 CFR part 63. Estimated number of respondents: 28. Frequency of response: Semi-annual, annual, periodic. Total estimated burden: 1,080 hours (per year). Burden is defined at 5 CFR 1320.3(b). Total estimated cost: $307,000 (per year), includes $180,000 annualized capital or operation and maintenance costs. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. Submit your comments on the Agency’s need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICR-related comments in the final rule. 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. This action will not impose any requirements on small entities. Of the 26 entities determined to be impacted by this action, only one is a small entity. This small entity is expected to not incur any costs associated with this action. More information on these small entity impacts is available in the RIA for this proposal. E. Unfunded Mandates Reform Act (UMRA) This action does not contain any unfunded mandate 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. The action affects private industry and does not impose economic costs on State or local governments. 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 not have substantial direct effects on tribal governments, on the relationship between the federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes, as specified in Executive Order 13175. PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 52219 Thus, Executive Order 13175 does not apply to this action. H. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks The EPA interprets Executive Order 13045 as applying to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of ‘‘covered regulatory action’’ in section 2–202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk. 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. The energy impacts estimated for this proposed rule increased only slightly the energy impacts estimated for the March 21, 2011, final rule which was concluded not to be a significant regulatory action under Executive Order 13211. Therefore, we conclude that this proposed rule, when implemented, is not likely to have a significant adverse effect on the supply, distribution, or use of energy. J. National Technology Transfer and Advancement Act (NTTAA) This rulemaking 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). The documentation for this decision is contained in the preamble to the March 2011 final rule (see 76 FR 15662). For the March 2011 final rule, the EPA determined that the rule would not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any E:\FR\FM\24AUP2.SGM 24AUP2 52220 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules minority or low-income population. Compared to the final rule, the proposed amendments are somewhat more stringent for some subcategories and, thus, the overall increased health benefits demonstrate that the conclusion from the environmental justice analysis conducted for the final rule are still valid. List of Subjects in 40 CFR Part 63 Environmental protection, Air pollution control, Hazardous substances, Reporting and recordkeeping requirements. Andrew Wheeler, Administrator. For the reasons stated in the preamble, 40 CFR part 63 is proposed to be amended as follows: PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES 1. The authority citation for part 63 continuous to read as follows: ■ Authority: 42 U.S.C. 7401, et seq. Subpart DDDDD—National Emission Standards For Hazardous Air Pollutants For Major Sources: Industrial, Commercial, And Institutional Boilers And Process Heaters 2. Section 63.7500 is amended by revising paragraph (a) introductory text and paragraphs (a)(1), (c), and (e) to read as follows: ■ jbell on DSKJLSW7X2PROD with PROPOSALS2 § 63.7500 What emission limitations, work practice standards, and operating limits must I meet? (a) You must meet the requirements in paragraphs (a)(1) through (3) of this section, except as provided in paragraphs (b) through (e) of this section. You must meet these requirements at all times the affected unit is operating, except as provided in paragraph (f) of this section. (1) You must meet each emission limit and work practice standard in Tables 1 through 3, and 11 through 15 to this subpart that applies to your boiler or process heater, for each boiler or process heater at your source, except as provided under § 63.7522. The output-based emission limits, in units of pounds per million Btu of steam output, in Tables 1 or 2 to this subpart are an alternative applicable only to boilers and process heaters that generate either steam, cogenerate steam with electricity, or both. The output-based emission limits, in units of pounds per megawatthour, in Tables 1 or 2 to this subpart are VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 an alternative applicable only to boilers that generate only electricity. Boilers that perform multiple functions (cogeneration and electricity generation) or supply steam to common headers would calculate a total steam energy output using equation 21 of § 63.7575 to demonstrate compliance with the output-based emission limits, in units of pounds per million Btu of steam output, in Tables 1 or 2 to this subpart. If you operate a new boiler or process heater, you can choose to comply with alternative limits as discussed in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, but on or after [DATE 3 YEARS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE Federal Register], you must comply with the emission limits in Table 1 to this subpart. If you operate an existing boiler or process heater, you can choose to comply with alternative limits as discussed in paragraphs (a)(1)(v) of this section, but on or after [DATE 3 YEARS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE Federal Register] you must comply with the emission limits in Table 2 to this subpart. (i) If your boiler or process heater commenced construction or reconstruction after June 4, 2010, and before May 20, 2011, you may comply with the emission limits in Table 11 or 14 to this subpart until January 31, 2016. (ii) If your boiler or process heater commenced construction or reconstruction on or after May 20, 2011, and before December 23, 2011, you may comply with the emission limits in Table 12 or 14 to this subpart until January 31, 2016. (iii) If your boiler or process heater commenced construction or reconstruction on or after December 23, 2011, and before April 1, 2013, you may comply with the emission limits in Table 13 or 14 to this subpart until January 31, 2016. (iv) If you operate a new boiler or process heater, you may comply with the emission limits in Table 1 or 14 until you must comply with the emission limits in Table 1 to this subpart. (v) If you operate an existing boiler or process heater, you may comply with the emission limits in Table 2 or 15 until you must comply with the emission limits in Table 2 to this subpart. * * * * * (c) Limited-use boilers and process heaters must complete a tune-up every 5 years as specified in § 63.7540. They are not subject to the emission limits in PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 Tables 1 and 2 or 11 through 15 to this subpart, the annual tune-up, or the energy assessment requirements in Table 3 to this subpart, or the operating limits in Table 4 to this subpart. * * * * * (e) Boilers and process heaters in the units designed to burn gas 1 fuels subcategory with a heat input capacity of less than or equal to 5 million Btu per hour must complete a tune-up every 5 years as specified in § 63.7540. Boilers and process heaters in the units designed to burn gas 1 fuels subcategory with a heat input capacity greater than 5 million Btu per hour and less than 10 million Btu per hour must complete a tune-up every 2 years as specified in § 63.7540. Boilers and process heaters in the units designed to burn gas 1 fuels subcategory are not subject to the emission limits in Tables 1 and 2 or 11 through 15 to this subpart, or the operating limits in Table 4 to this subpart. * * * * * ■ 3. Section 63.7505 is amended by revising paragraph (c) to read as follows: § 63.7505 What are my general requirements for complying with this subpart? * * * * * (c) You must demonstrate compliance with all applicable emission limits using performance stack testing, fuel analysis, or continuous monitoring systems (CMS), including a continuous emission monitoring system (CEMS), continuous opacity monitoring system (COMS), continuous parameter monitoring system (CPMS), or particulate matter continuous parameter monitoring system (PM CPMS), where applicable. You may demonstrate compliance with the applicable emission limit for hydrogen chloride (HCl), mercury, or total selected metals (TSM) using fuel analysis if the emission rate calculated according to § 63.7530(c) is less than the applicable emission limit. For gaseous fuels, you may not use fuel analyses to comply with the TSM alternative standard or the HCl standard. Otherwise, you must demonstrate compliance for HCl, mercury, or TSM using performance stack testing, if subject to an applicable emission limit listed in Tables 1, 2, or 11 through 15 to this subpart. * * * * * ■ 4. Section 63.7510 is amended by revising paragraph (a) introductory text and paragraphs (b), (c), (f), and (j) to read as follows: E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules jbell on DSKJLSW7X2PROD with PROPOSALS2 § 63.7510 What are my initial compliance requirements and by what date must I conduct them? (a) For each boiler or process heater that is required or that you elect to demonstrate compliance with any of the applicable emission limits in Tables 1 or 2 or 11 through 15 of this subpart through performance (stack) testing, your initial compliance requirements include all the following: * * * * * (b) For each boiler or process heater that you elect to demonstrate compliance with the applicable emission limits in Tables 1 or 2 or 11 through 15 to this subpart for HCl, mercury, or TSM through fuel analysis, your initial compliance requirement is to conduct a fuel analysis for each type of fuel burned in your boiler or process heater according to § 63.7521 and Table 6 to this subpart and establish operating limits according to § 63.7530 and Table 8 to this subpart. The fuels described in paragraph (a)(2)(i) and (ii) of this section are exempt from these fuel analysis and operating limit requirements. The fuels described in paragraph (a)(2)(ii) of this section are exempt from the chloride fuel analysis and operating limit requirements. Boilers and process heaters that use a CEMS for mercury or HCl are exempt from the performance testing and operating limit requirements specified in paragraph (a) of this section for the HAP for which CEMS are used. (c) If your boiler or process heater is subject to a carbon monoxide (CO) limit, your initial compliance demonstration for CO is to conduct a performance test for CO according to Table 5 to this subpart or conduct a performance evaluation of your continuous CO monitor, if applicable, according to § 63.7525(a). Boilers and process heaters that use a CO CEMS to comply with the applicable alternative CO CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this subpart, as specified in § 63.7525(a), are exempt from the initial CO performance testing and oxygen concentration operating limit requirements specified in paragraph (a) of this section. * * * * * (f) For new or reconstructed affected sources (as defined in § 63.7490), you must complete the initial compliance demonstration with the emission limits no later than July 30, 2013, or within 180 days after startup of the source, whichever is later. (1) If you are demonstrating compliance with an emission limit in Tables 11 through 13 to this subpart that is less stringent (that is, higher) than the applicable emission limit in Table 14 to VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 this subpart, you must demonstrate compliance with the applicable emission limit in Table 14 no later than July 29, 2016. (2) If you are demonstrating compliance with an emission limit in Table 14 to this subpart that is less stringent (that is, higher) than the applicable emission limit in Table 1 to this subpart, you must demonstrate compliance with the applicable emission limit in Table 1 to this subpart no later than [date 3 years after date of publication of final rule in the Federal Register]. * * * * * (j) For existing affected sources (as defined in § 63.7490) that have not operated between the effective date of the rule and the compliance date that is specified for your source in § 63.7495, you must complete the initial compliance demonstration, if subject to the emission limits in Tables 2 or 14, to this subpart, as applicable, as specified in paragraphs (a) through (d) of this section, no later than 180 days after the re-start of the affected source and according to the applicable provisions in § 63.7(a)(2) as cited in Table 10 to this subpart. You must complete an initial tune-up by following the procedures described in § 63.7540(a)(10)(i) through (vi) no later than 30 days after the restart of the affected source and, if applicable, complete the one-time energy assessment specified in Table 3 to this subpart, no later than the compliance date specified in § 63.7495. * * * * * ■ 5. Section 63.7515 is amended by revising paragraphs (b), (c), (e), (g), and (i) to read as follows: § 63.7515 When must I conduct subsequent performance tests, fuel analyses, or tune-ups? * * * * * (b) If your performance tests for a given pollutant for at least 2 consecutive years show that your emissions are at or below 75 percent of the emission limit (or, in limited instances as specified in Tables 1 and 2 or 11 through 15 to this subpart, at or below the emission limit) for the pollutant, and if there are no changes in the operation of the individual boiler or process heater or air pollution control equipment that could increase emissions, you may choose to conduct performance tests for the pollutant every third year. Each such performance test must be conducted no more than 37 months after the previous performance test. If you elect to demonstrate compliance using emission averaging under § 63.7522, you must continue to conduct performance tests annually. The requirement to test at PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 52221 maximum chloride input level is waived unless the stack test is conducted for HCl. The requirement to test at maximum mercury input level is waived unless the stack test is conducted for mercury. The requirement to test at maximum TSM input level is waived unless the stack test is conducted for TSM. (c) If a performance test shows emissions exceeded the emission limit or 75 percent of the emission limit (as specified in Tables 1 and 2 or 11 through 15 to this subpart) for a pollutant, you must conduct annual performance tests for that pollutant until all performance tests over a consecutive 2-year period meet the required level (at or below 75 percent of the emission limit, as specified in Tables 1 and 2 or 11 through 15 to this subpart). * * * * * (e) If you demonstrate compliance with the mercury, HCl, or TSM based on fuel analysis, you must conduct a monthly fuel analysis according to § 63.7521 for each type of fuel burned that is subject to an emission limit in Tables 1, 2, or 11 through 15 to this subpart. You may comply with this monthly requirement by completing the fuel analysis any time within the calendar month as long as the analysis is separated from the previous analysis by at least 14 calendar days. If you burn a new type of fuel, you must conduct a fuel analysis before burning the new type of fuel in your boiler or process heater. You must still meet all applicable continuous compliance requirements in § 63.7540. If each of 12 consecutive monthly fuel analyses demonstrates 75 percent or less of the compliance level, you may decrease the fuel analysis frequency to quarterly for that fuel. If any quarterly sample exceeds 75 percent of the compliance level or you begin burning a new type of fuel, you must return to monthly monitoring for that fuel, until 12 months of fuel analyses are again less than 75 percent of the compliance level. If sampling is conducted on 1 day per month, samples should be no less than 14 days apart, but if multiple samples are taken per month, the 14-day restriction does not apply. * * * * * (g) For affected sources (as defined in § 63.7490) that have not operated since the previous compliance demonstration and more than 1 year has passed since the previous compliance demonstration, you must complete the subsequent compliance demonstration, if subject to the emission limits in Tables 1, 2, or 11 through 15 to this subpart, no later than E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules § 63.7520 What stack tests and procedures must I use? * * * * * (d) You must conduct a minimum of three separate test runs for each performance test required in this section, as specified in § 63.7(e)(3). Each test run must comply with the minimum applicable sampling times or volumes specified in Tables 1 and 2 or 11 through 15 to this subpart. * * * * * ■ 7. Section 63.7521 is amended by revising paragraphs (a) and (c)(1)(ii) to read as follows: § 63.7521 What fuel analyses, fuel specification, and procedures must I use? (a) For solid and liquid fuels, you must conduct fuel analyses for chloride and mercury according to the procedures in paragraphs (b) through (e) of this section and Table 6 to this subpart, as applicable. For solid fuels and liquid fuels, you must also conduct fuel analyses for TSM if you are opting to comply with the TSM alternative standard. For gas 2 (other) fuels, you must conduct fuel analyses for mercury according to the procedures in paragraphs (b) through (e) of this section and Table 6 to this subpart, as applicable. For gaseous fuels, you may not use fuel analyses to comply with the TSM alternative standard or the HCl standard. For purposes of complying with this section, a fuel gas system that consists of multiple gaseous fuels collected and mixed with each other is considered a single fuel type and sampling and analysis is only required on the combined fuel gas system that will feed the boiler or process heater. Sampling and analysis of the individual gaseous streams prior to combining is not required. You are not required to conduct fuel analyses for fuels used for only startup, unit shutdown, and transient flame stability purposes. You are required to conduct fuel analyses only for fuels and units that are subject to emission limits for mercury, HCl, or TSM in Tables 1 and 2 or 11 through 15 to this subpart. Gaseous and liquid fuels are exempt from the sampling requirements in paragraphs (c) and (d) of this section. * * * * * (c) * * * (1) * * * (ii) Each composite sample will consist of a minimum of three samples collected at approximately equal intervals during the testing period for sampling during performance stack testing. * * * * * (or TSM), HCl, or mercury from unit, i, in units of pounds per million Btu of heat input. Determine the emission rate for PM (or TSM), HCl, or mercury by performance testing according to Table 5 to this subpart, or by fuel analysis for jbell on DSKJLSW7X2PROD with PROPOSALS2 Where: AveWeightedEmissions = Average weighted emissions for PM (or TSM), HCl, or mercury, in units of pounds per million Btu of heat input. Er = Emission rate (as determined during the initial compliance demonstration) of PM Where: AveWeightedEmissions = Average weighted emissions for PM (or TSM), HCl, or VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 mercury, in units of pounds per million Btu of steam output. Er = Emission rate (as determined during the initial compliance demonstration) of PM PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 8. Section 63.7522 is amended by revising paragraph (b) introductory text and paragraphs (d), (e)(1), (2), (h), and (j)(1) to read as follows: ■ § 63.7522 Can I use emissions averaging to comply with this subpart? * * * * * (b) For a group of two or more existing boilers or process heaters in the same subcategory that each vent to a separate stack, you may average PM (or TSM), HCl, or mercury emissions among existing units to demonstrate compliance with the limits in Table 2 or 15 to this subpart as specified in paragraph (b)(1) through (3) of this section, if you satisfy the requirements in paragraphs (c) through (g) of this section. * * * * * (d) The averaged emissions rate from the existing boilers and process heaters participating in the emissions averaging option must not exceed 90 percent of the limits in Table 2 or 15 to this subpart at all times the affected units are subject to numeric emission limits following the compliance date specified in § 63.7495. (e) * * * (1) You must use Equation 1a or 1b or 1c of this section to demonstrate that the PM (or TSM), HCl, or mercury emissions from all existing units participating in the emissions averaging option for that pollutant do not exceed the emission limits in Table 2 or 15 to this subpart. Use Equation 1a if you are complying with the emission limits on a heat input basis, use Equation 1b if you are complying with the emission limits on a steam generation (output) basis, and use Equation 1c if you are complying with the emission limits on a electric generation (output) basis. HCl or mercury or TSM using the applicable equation in § 63.7530(c). Hm = Maximum rated heat input capacity of unit, i, in units of million Btu per hour. n = Number of units participating in the emissions averaging option. 1.1 = Required discount factor. (or TSM), HCl, or mercury from unit, i, in units of pounds per million Btu of steam output. Determine the emission rate for PM (or TSM), HCl, or mercury by E:\FR\FM\24AUP2.SGM 24AUP2 EP24AU20.001</GPH> 180 days after the re-start of the affected source and according to the applicable provisions in § 63.7(a)(2) as cited in Table 10 to this subpart. You must complete a subsequent tune-up by following the procedures described in § 63.7540(a)(10)(i) through (vi) and the schedule described in § 63.7540(a)(13) for units that are not operating at the time of their scheduled tune-up. * * * * * (i) If you operate a CO CEMS that meets the Performance Specifications outlined in § 63.7525(a)(3) of this subpart to demonstrate compliance with the applicable alternative CO CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this subpart, you are not required to conduct CO performance tests and are not subject to the oxygen concentration operating limit requirement specified in § 63.7510(a). ■ 6. Section 63.7520 is amended by revising paragraph (d) to read as follows: EP24AU20.000</GPH> 52222 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules Where: AveWeightedEmissions = Average weighted emission level for PM (or TSM), HCl, or mercury, in units of pounds per million Btu of heat input. Er = Emission rate (as determined during the most recent compliance demonstration) of PM (or TSM), HCl, or mercury from unit, i, in units of pounds per million Btu of heat input. Determine the emission rate for PM (or TSM), HCl, or mercury by performance testing according to Table 5 to this subpart, or by fuel analysis for HCl or mercury or TSM using the applicable equation in § 63.7530(c). Sm = Maximum steam generation capacity by unit, i, in units of pounds per hour. Cfi = Conversion factor, calculated from the most recent compliance test, in units of million Btu of heat input per pounds of steam generated for unit, i. 1.1 = Required discount factor. are determined by the use of Equation 6 of this section. * * * * (h) For a group of two or more existing affected units, each of which vents through a single common stack, you may average PM (or TSM), HCl, or mercury emissions to demonstrate compliance with the limits for that pollutant in Table 2 or 15 to this subpart if you satisfy the requirements in paragraph (i) or (j) of this section. * * * * * (j) * * * (1) Conduct performance tests according to procedures specified in § 63.7520 in the common stack if affected units from other subcategories vent to the common stack. The emission limits that the group must comply with VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 (2) If you are not capable of determining the maximum rated heat Where: En = HAP emission limit, pounds per million British thermal units (lb/MMBtu) or parts per million (ppm). ELi = Appropriate emission limit from Table 2 or 15 to this subpart for unit i, in units of lb/MMBtu or ppm. Hi = Heat input from unit i, MMBtu. * * * * * 9. Section 63.7525 is amended by revising paragraphs (a), (2), (2)(iv), (l), and (m) introductory text to read as follows: ■ § 63.7525 What are my monitoring, installation, operation, and maintenance requirements? (a) If your boiler or process heater is subject to a CO emission limit in Tables 1, 2, or 11 through 15 to this subpart, you must install, operate, and maintain an oxygen analyzer system, as defined in § 63.7575, or install, certify, operate and maintain continuous emission monitoring systems for CO and oxygen (or carbon dioxide (CO2)) according to the procedures in paragraphs (a)(1) through (6) of this section. * * * * * (2) To demonstrate compliance with the applicable alternative CO CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this subpart, you must install, certify, operate, and PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 input capacity of one or more boilers that generate steam, you may use Equation 2 of this section as an alternative to using Equation 1a of this section to demonstrate that the PM (or TSM), HCl, or mercury emissions from all existing units participating in the emissions averaging option do not exceed the emission limits for that pollutant in Table 2 or 15 to this subpart that are in pounds per million Btu of heat input. maintain a CO CEMS and an oxygen analyzer according to the applicable procedures under Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B; part 75 of this chapter (if an CO2 analyzer is used); the sitespecific monitoring plan developed according to § 63.7505(d); and the requirements in § 63.7540(a)(8) and paragraph (a) of this section. Any boiler or process heater that has a CO CEMS that is compliant with Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B, a site-specific monitoring plan developed according to § 63.7505(d), and the requirements in § 63.7540(a)(8) and paragraph (a) of this section must use the CO CEMS to comply with the applicable alternative CO CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this subpart. * * * * * (iv) Any CO CEMS that does not comply with § 63.7525(a) cannot be used to meet any requirement in this subpart to demonstrate compliance with a CO emission limit listed in Tables 1, 2, or 11 through 15 to this subpart. * * * * * (l) For each unit for which you decide to demonstrate compliance with the mercury or HCl emissions limits in Tables 1 or 2 or 11 through 15 of this subpart by use of a CEMS for mercury or HCl, you must install, certify, maintain, and operate a CEMS measuring emissions discharged to the E:\FR\FM\24AUP2.SGM 24AUP2 EP24AU20.004</GPH> equation in § 63.7530(c). If you are taking credit for energy conservation measures from a unit according to § 63.7533, use the adjusted emission level for that unit, Eadj, determined according to § 63.7533 for that unit. Eo = Maximum electric generating output capacity of unit, i, in units of megawatt hour, as defined in § 63.7575. n = Number of units participating in the emissions averaging option. 1.1 = Required discount factor. So = Maximum steam output capacity of unit, i, in units of million Btu per hour, as defined in § 63.7575. n = Number of units participating in the emissions averaging option. 1.1 = Required discount factor. EP24AU20.003</GPH> Where: AveWeightedEmissions = Average weighted emissions for PM (or TSM), HCl, or mercury, in units of pounds per megawatt hour. Er = Emission rate (as determined during the initial compliance demonstration) of PM (or TSM), HCl, or mercury from unit, i, in units of pounds per megawatt hour. Determine the emission rate for PM (or TSM), HCl, or mercury by performance testing according to Table 5 to this subpart, or by fuel analysis for HCl or mercury or TSM using the applicable * jbell on DSKJLSW7X2PROD with PROPOSALS2 according to § 63.7533, use the adjusted emission level for that unit, Eadj, determined according to § 63.7533 for that unit. EP24AU20.002</GPH> performance testing according to Table 5 to this subpart, or by fuel analysis for HCl or mercury or TSM using the applicable equation in § 63.7530(c). If you are taking credit for energy conservation measures from a unit 52223 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules atmosphere and record the output of the system as specified in paragraphs (l)(1) through (8) of this section. For HCl, this option for an affected unit takes effect on the date a final performance specification for a HCl CEMS is published in the Federal Register or the date of approval of a site-specific monitoring plan. (m) If your unit is subject to a HCl emission limit in Tables 1, 2, or 11 through 15 of this subpart and you have an acid gas wet scrubber or dry sorbent injection control technology and you elect to use an SO2 CEMS to demonstrate continuous compliance with the HCl emission limit, you must install the monitor at the outlet of the boiler or process heater, downstream of all emission control devices, and you must install, certify, operate, and maintain the CEMS according to either part 60 or part 75 of this chapter. * * * * * ■ 10. Section 63.7530 is amended by revising paragraphs (b)(4)(ii)(E) and (iii) and the introductory text of paragraph (h) to read as follows: § 63.7530 How do I demonstrate initial compliance with the emission limitations, fuel specifications and work practice standards? jbell on DSKJLSW7X2PROD with PROPOSALS2 * * * * * (b) * * * (4) * * * (ii) * * * (E) Use EPA Method 5 of appendix A to part 60 of this chapter to determine PM emissions. For each performance test, conduct three separate runs under the conditions that exist when the affected source is operating at the highest load or capacity level reasonably expected to occur. Conduct each test run to collect a minimum sample volume specified in Tables 1, 2, or 11 through 15 to this subpart, as applicable, for determining compliance with a new source limit or an existing source limit. Calculate the average of the results from three runs to determine compliance. You need not determine the PM collected in the impingers (‘‘back half’’) of the Method 5 particulate sampling train to demonstrate compliance with the PM standards of this subpart. This shall not preclude the permitting authority from requiring a determination of the ‘‘back half’’ for other purposes. * * * * * (iii) For a particulate wet scrubber, you must establish the minimum pressure drop and liquid flow rate as defined in § 63.7575, as your operating limits during the three-run performance test during which you demonstrate compliance with your applicable limit. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 If you use a wet scrubber and you conduct separate performance tests for PM and TSM emissions, you must establish one set of minimum scrubber liquid flow rate and pressure drop operating limits. If you conduct multiple performance tests, you must set the minimum liquid flow rate and pressure drop operating limits at the higher of the minimum values established during the performance tests. * * * * * (h) If you own or operate a unit subject to emission limits in Tables 1 or 2 or 11 through 15 to this subpart, you must meet the work practice standard according to Table 3 of this subpart. During startup and shutdown, you must only follow the work practice standards according to items 5 and 6 of Table 3 of this subpart. * * * * * ■ 11. Section 63.7533 is amended by revising paragraphs (a), (e), and (f) to read as follows: § 63.7533 Can I use efficiency credits earned from implementation of energy conservation measures to comply with this subpart? (a) If you elect to comply with the alternative equivalent output-based emission limits, instead of the heat input-based limits listed in Table 2 or 15 to this subpart, and you want to take credit for implementing energy conservation measures identified in an energy assessment, you may demonstrate compliance using efficiency credits according to the procedures in this section. You may use this compliance approach for an existing affected boiler for demonstrating initial compliance according to § 63.7522(e) and for demonstrating monthly compliance according to § 63.7522(f). Owners or operators using this compliance approach must establish an emissions benchmark, calculate and document the efficiency credits, develop an Implementation Plan, comply with the general reporting requirements, and apply the efficiency credit according to the procedures in paragraphs (b) through (f) of this section. You cannot use this compliance approach for a new or reconstructed affected boiler. Additional guidance from the Department of Energy on efficiency credits is available at: https:// www.epa.gov/ttn/atw/boiler/ boilerpg.html. * * * * * (e) The emissions rate as calculated using Equation 20 of this section from each existing boiler participating in the efficiency credit option must be in PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 compliance with the limits in Table 2 or 15 to this subpart at all times the affected unit is subject to numeric emission limits, following the compliance date specified in § 63.7495. (f) You must use Equation 20 of this section to demonstrate initial compliance by demonstrating that the emissions from the affected boiler participating in the efficiency credit compliance approach do not exceed the emission limits in Table 2 or 15 to this subpart. Where: Eadj = Emission level adjusted by applying the efficiency credits earned, lb per million Btu steam output (or lb per MWh) for the affected boiler. Em = Emissions measured during the performance test, lb per million Btu steam output (or lb per MWh) for the affected boiler. ECredits = Efficiency credits from Equation 19 for the affected boiler. * * * * * 12. Section 63.7540 is amended by: a. Revising paragraphs (a), (8), and (19) introductory text; and ■ b. Revising paragraphs (a)(8)(ii), (9), and (b). The revisions read as follows: ■ ■ § 63.7540 How do I demonstrate continuous compliance with the emission limitations, fuel specifications and work practice standards? (a) You must demonstrate continuous compliance with each emission limit in Tables 1 and 2 or 11 through 15 to this subpart, the work practice standards in Table 3 to this subpart, and the operating limits in Table 4 to this subpart that applies to you according to the methods specified in Table 8 to this subpart and paragraphs (a)(1) through (19) of this section. * * * * * (8) To demonstrate compliance with the applicable alternative CO CEMS emission limit listed in Tables 1, 2, or 11 through 15 to this subpart, you must meet the requirements in paragraphs (a)(8)(i) through (iv) of this section. * * * * * (ii) Maintain a CO emission level below or at your applicable alternative CO CEMS-based standard in Tables 1 or 2 or 11 through 15 to this subpart at all times the affected unit is subject to numeric emission limits. * * * * * (9) The owner or operator of a boiler or process heater using a PM CPMS or a PM CEMS to meet requirements of this subpart shall install, certify (PM CEMS only), operate, and maintain the PM CPMS or PM CEMS in accordance with E:\FR\FM\24AUP2.SGM 24AUP2 EP24AU20.005</GPH> 52224 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules § 63.7545 What notifications must I submit and when? * * * * (e) * * * (3) A summary of the maximum CO emission levels recorded during the performance test to show that you have met any applicable emission standard in Tables 1, 2, or 11 through 15 to this subpart, if you are not using a CO CEMS to demonstrate compliance. * * * * * jbell on DSKJLSW7X2PROD with PROPOSALS2 * Where: SOM = Total steam output for multi-function boiler, MMBtu S1 = Energy content of steam sent directly to the process and/or used for heating, MMBtu S2 = Energy content of turbine steam sent to the process plus energy in electricity according to (2) above, MMBtu MW(3) = Electricity generated according to paragraph (3) of this definition, MWh VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 14. Section 63.7555 is amended by revising paragraph (d) introductory text and paragraph (5) to read as follows: ■ § 63.7555 What records must I keep? * * * * * (d) For each boiler or process heater subject to an emission limit in Tables 1, 2, or 11 through 15 to this subpart, you must also keep the applicable records in paragraphs (d)(1) through (11) of this section. * * * * * (5) If, consistent with § 63.7515(b), you choose to stack test less frequently than annually, you must keep a record that documents that your emissions in the previous stack test(s) were less than 75 percent of the applicable emission limit (or, in specific instances noted in Tables 1 and 2 or 11 through 15 to this subpart, less than the applicable emission limit), and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the relevant pollutant to increase within the past year. * * * * * ■ 15. Section 63.7575 is amended by: ■ a. Adding, in alphabetical order, a definition for ‘‘12-month rolling average’’; ■ b. Revising the definition of ‘‘Other gas 1 fuel’’; and ■ c. Revising paragraphs (3) and (4) under the definition of ‘‘Steam output.’’ The additions and revisions read as follows: § 63.7575 subpart? What definitions apply to this * * * * * 12-month rolling average means the arithmetic mean of the previous 12 CFn = Conversion factor for the appropriate subcategory for converting electricity generated according to paragraph (3) of this definition to equivalent steam energy, MMBtu/MWh CFn for emission limits for boilers in the unit designed to burn solid fuel subcategory = 10.8 CFn PM and CO emission limits for boilers in one of the subcategories of units designed to burn coal = 11.7 PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 months of valid fuel analysis data. The 12 months should be consecutive, but not necessarily continuous if operations were intermittent. * * * * * Other gas 1 fuel means a gaseous fuel that is not natural gas or refinery gas and does not exceed a maximum mercury concentration of 40 micrograms/cubic meters of gas. * * * * * Steam output * * * * * * * * (3) For a boiler that generates only electricity, the alternate output-based emission limits would be the appropriate emission limit from Table 1 or 2 or 14 or 15 of this subpart in units of pounds per million Btu heat input (lb per MWh). (4) For a boiler that performs multiple functions and produces steam to be used for any combination of paragraphs (1), (2) and (3) of this definition that includes electricity generation of paragraph (3) of this definition, the total energy output, in terms of MMBtu of steam output, is the sum of the energy content of steam sent directly to the process and/or used for heating (S1), the energy content of turbine steam sent to process plus energy in electricity according to paragraph (2) of this definition (S2), and the energy content of electricity generated by a electricity only turbine as paragraph (3) of this definition (MW3) and would be calculated using Equation 21 of this section. In the case of boilers supplying steam to one or more common headers, S1, S2, and MW(3) for each boiler would be calculated based on the its (steam energy) contribution (fraction of total steam energy) to the common header. CFn PM and CO emission limits for boilers in one of the subcategories of units designed to burn biomass = 12.1 CFn for emission limits for boilers in one of the subcategories of units designed to burn liquid fuel = 11.2 CFn for emission limits for boilers in the unit designed to burn gas 2 (other) subcategory = 6.2 * * * * * 16. Table 1 to subpart DDDDD is amended to read as follows: ■ E:\FR\FM\24AUP2.SGM 24AUP2 EP24AU20.006</GPH> your site-specific monitoring plan as required in § 63.7505(d). * * * * * (19) If you choose to comply with the PM filterable emissions limit by using PM CEMS you must install, certify, operate, and maintain a PM CEMS and record the output of the PM CEMS as specified in paragraphs (a)(19)(i) through (vii) of this section. The compliance limit will be expressed as a 30-day rolling average of the numerical emissions limit value applicable for your unit in Tables 1 or 2 or 11 through 15 of this subpart. * * * * * (b) You must report each instance in which you did not meet each emission limit and operating limit in Tables 1 through 4 or 11 through 15 to this subpart that apply to you. These instances are deviations from the emission limits or operating limits, respectively, in this subpart. These deviations must be reported according to the requirements in § 63.7550. * * * * * ■ 13. Section 63.7545 is amended by revising paragraph (e)(3) to read as follows: 52225 52226 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . 1. Units in all subcategories designed to burn solid fuel. a. HCl ........................... 3.0E–04 lb per MMBtu of heat input 4.1E–04 lb per MMBtu of steam output or 3.9E–03 lb per MWh. b. Mercury .................... 8.0E–07 input. per MMBtu of heat 8.7E–07 a lb per MMBtu of steam output or 1.1E–05 a lb per MWh. 2. Units designed to burn coal/solid fossil fuel. a. Filterable PM (or TSM). 1.1E–03 lb per MMBtu of heat input; or (2.3E–05 lb per MMBtu of heat input). 3. Pulverized coal boilers designed to burn coal/solid fossil fuel. a. Carbon monoxide (CO) (or CEMS). 4. Stokers/others designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 5. Fluidized bed units designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 6. Fluidized bed units with an integrated heat exchanger designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 7. Stokers/sloped grate/ others designed to burn wet biomass fuel. a. CO (or CEMS) ......... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 140 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 590 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (390 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 1.3E–02 lb per MMBtu of heat input; or (2.6E–05 lb per MMBtu of heat input). 1.1E–03 lb per MMBtu of steam output or 1.4E–02 lb per MWh; or (2.7E–05 lb per MMBtu of steam output or 2.9E–04 lb per MWh). 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. b. Filterable PM (or TSM). 8. Stokers/sloped grate/ others designed to burn kiln-dried biomass fuel. a. CO ........................... 460 ppm by volume on a dry basis corrected to 3-percent oxygen. b. Filterable PM (or TSM). 3.0E–02 lb per MMBtu of heat input; or (5.0E–03 lb per MMBtu of heat input). 9. Fluidized bed units a. CO (or CEMS) ......... designed to burn biomass/bio-based solids. jbell on DSKJLSW7X2PROD with PROPOSALS2 b. Filterable PM (or TSM). 10. Suspension burners a. CO (or CEMS) ......... designed to burn biomass/bio-based solids. VerDate Sep<11>2014 a lb 18:10 Aug 21, 2020 Jkt 250001 130 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 4.1E–03 lb per MMBtu of heat input; or (8.4E–06 a lb per MMBtu of heat input). 220 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (2,000 ppm by volume on a dry basis corrected to 3-percent oxygen,d 10-day rolling average). PO 00000 Frm 00030 Fmt 4701 Using this specified sampling volume or test run duration . . . For M26A, collect a minimum of 1 dscm per run; for M26 collect a minimum of 120 liters per run. For M29, collect a minimum of 4 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 4 dscm. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. 0.12 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 1.2E–01 lb per MMBtu of steam output or 1.5 lb per MWh; threerun average. 1 hr minimum sampling time. 6.1E–01 lb per MMBtu of steam output or 6.5 lb per MWh; threerun average. 1 hr minimum sampling time. 1.4E–02 lb per MMBtu of steam output or 1.9E–01 lb per MWh; or (2.7E–05 lb per MMBtu of steam output or 3.7E–04 lb per MWh). 4.3E–01 lb per MMBtu of steam output or 5.1 lb per MWh. Collect a minimum of 2 dscm per run. 3.5E–02 lb per MMBtu of steam output or 4.2E–01 lb per MWh; or (5.2E–03 lb per MMBtu of steam output or 7.0E–02 lb per MWh). 1.3E–01 lb per MMBtu of steam output or 1.5 lb per MWh; threerun average. Collect a minimum of 2 dscm per run. 5.0E–03 lb per MMBtu of steam output or 5.8E–02 lb per MWh; or (1.1E–05 a lb per MMBtu of steam output or 1.2E–04 a lb per MWh). 0.18 lb per MMBtu of steam output or 2.5 lb per MWh; three-run average. Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules 52227 TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . 11. Dutch Ovens/Pile burners designed to burn biomass/biobased solids. For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . b. Filterable PM (or TSM). 3.0E–02 lb per MMBtu of heat input; or (8.0E–03 lb per MMBtu of heat input). a. CO (or CEMS) ......... 330 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to 3-percent oxygen,d 10-day rolling average). 2.5E–03 lb per MMBtu of heat input; or (3.9E–05 lb per MMBtu of heat input). 3.1E–02 lb per MMBtu of steam output or 4.2E–01 lb per MWh; or (8.1E–03 lb per MMBtu of steam output or 1.2E–01 lb per MWh). 3.5E–01 lb per MMBtu of steam output or 3.6 lb per MWh; threerun average. b. Filterable PM (or TSM). 12. Fuel cell units dea. CO ........................... signed to burn biomass/bio-based solids. b. Filterable PM (or TSM). 910 ppm by volume on a dry basis corrected to 3-percent oxygen. 13. Hybrid suspension grate boiler designed to burn biomass/biobased solids. 180 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (900 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 2.6E–02 lb per MMBtu of heat input; or (4.4E–04 lb per MMBtu of heat input). a. CO (or CEMS) ......... b. Filterable PM (or TSM). 14. Units designed to burn liquid fuel. 15. Units designed to burn heavy liquid fuel. jbell on DSKJLSW7X2PROD with PROPOSALS2 18. Units designed to burn gas 2 (other) gases. VerDate Sep<11>2014 Collect a minimum of 2 dscm per run. 3.3E–02 lb per MMBtu of steam output or 3.7E–01 lb per MWh; or (5.5E–04 lb per MMBtu of steam output or 6.2E–03 lb per MWh). 7.7E–05 lb per MMBtu of steam output or 9.7E–04 lb per MWh. Collect a minimum of 3 dscm per run. 4.8E–07 input. per MMBtu of heat 5.3E–07 a lb per MMBtu of steam output or 6.7E–06 a lb per MWh. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average. 1.9E–03 lb per MMBtu of heat input; or (6.1E–06 lb per MMBtu of heat input). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 2.1E–03 lb per MMBtu of steam output or 2.7E–02 lb per MWh; or (6.7E–6 lb per MMBtu of steam output or 8.5E–5 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh. 1.2E–03 a lb per MMBtu of steam output or 1.6E–02 a lb per MWh; or (3.2E–05 lb per MMBtu of steam output or 4.0E–04 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. b. Filterable PM (or TSM). 17. Units designed to burn liquid fuel that are non-continental units. 2.0E–02 lb per MMBtu of steam output or 1.6E–01 lb per MWh; or (5.1E–05 lb per MMBtu of steam output or 4.1E–04 lb per MWh). 0.22 lb per MMBtu of steam output or 2.0 lb per MWh; three-run average. b. Mercury .................... a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen. 1.1E–03 a lb per MMBtu of heat input; or (2.9E–05 lb per MMBtu of heat input). a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, 3run average based on stack test. b. Filterable PM (or TSM). 2.3E–02 lb per MMBtu of heat input; or (8.6E–04 lb per MMBtu of heat input). a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen. b. HCl ........................... c. Mercury .................... 18:10 Aug 21, 2020 Jkt 250001 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 7.0E–05 lb per MMBtu of heat input a lb Collect a minimum of 2 dscm per run. 3.4E–03 lb per MMBtu of steam output or 3.5E–02 lb per MWh; or (5.2E–05 lb per MMBtu of steam output or 5.5E–04 lb per MWh). 1.1 lb per MMBtu of steam output or 1.0E+01 lb per MWh. a. HCl ........................... b. Filterable PM (or TSM). 16. Units designed to burn light liquid fuel. 1.1E–02 lb per MMBtu of heat input; or (2.9E–05 a lb per MMBtu of heat input). Using this specified sampling volume or test run duration . . . 1 hr minimum sampling time. 1 hr minimum sampling time. For M26A: Collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 4 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 4 dscm. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. 2.5E–02 lb per MMBtu of steam output or 3.2E–01 lb per MWh; or (9.4E–04 lb per MMBtu of steam output or 1.2E–02 lb per MWh). 0.16 lb per MMBtu of steam output or 1.0 lb per MWh. Collect a minimum of 4 dscm per run. 1.7E–03 lb per MMBtu of heat input 2.9E–03 lb per MMBtu of steam output or 1.8E–02 lb per MWh. 7.9E–06 lb per MMBtu of heat input 1.4E–05 lb per MMBtu of steam output or 8.3E–05 lb per MWh. For M26A, Collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 3 dscm. PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time. 52228 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . d. Filterable PM (or TSM). 7.3E–03 lb per MMBtu of heat input; or (2.1E–04 lb per MMBtu of heat input). 1.3E–02 lb per MMBtu of steam output or 7.6E–02 lb per MWh; or (3.5E–04 lb per MMBtu of steam output or 2.2E–03 lb per MWh). Using this specified sampling volume or test run duration . . . Collect a minimum of 3 dscm per run. a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. c If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before April 1, 2013, you may comply with the emission limits in Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before [date 3 years after date of publication of final rule in the Federal Register] you may comply with the emission limits in Table 14 to this subpart. On and after [date 3 years after date of publication of final rule in the Federal Register], you must comply with the emission limits in Table 1 to this subpart. d An owner or operator may request an alternative test method under § 63.7 of this chapter, in order that compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber media, etc. 17. Table 2 to subpart DDDDD is amended to read as follows: ■ jbell on DSKJLSW7X2PROD with PROPOSALS2 TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . 1. Units in all subcategories designed to burn solid fuel. a. HCl ........................... 2.0E–02 lb per MMBtu of heat input 2.3E–02 lb per MMBtu of steam output or 0.26 lb per MWh. b. Mercury .................... 5.4E–06 lb per MMBtu of heat input 6.2E–06 lb per MMBtu of steam output or 6.9E–05 lb per MWh. 2. Units design to burn coal/solid fossil fuel. a. Filterable PM (or TSM). 3.9E–02 lb per MMBtu of heat input; or (5.3E–05 lb per MMBtu of heat input). 3. Pulverized coal boilers designed to burn coal/solid fossil fuel. a. CO (or CEMS) ......... 4. Stokers/others designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 5. Fluidized bed units designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 6. Fluidized bed units with an integrated heat exchanger designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 7. Stokers/sloped grate/ others designed to burn wet biomass fuel. a. CO (or CEMS) ......... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (320 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 150 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (340 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (230 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 140 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (150 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 1,100 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (720 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30-day rolling average). 4.1E–02 lb per MMBtu of steam output or 4.8E–01 lb per MWh; or (5.6E–05 lb per MMBtu of steam output or 6.5E–04 lb per MWh). 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 PO 00000 Frm 00032 Fmt 4701 Using this specified sampling volume or test run duration . . . For M26A, Collect a minimum of 1 dscm per run; for M26, collect a minimum of 120 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 3 dscm. Collect a minimum of 2 dscm per run. 1 hr minimum sampling time. 0.14 lb per MMBtu of steam output or 1.6 lb per MWh; three-run average. 1 hr minimum sampling time. 0.12 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 1.3E–01 lb per MMBtu of steam output or 1.5 lb per MWh; threerun average. 1 hr minimum sampling time. 1.1 lb per MMBtu of steam output or 13 lb per MWh; three-run average. 1 hr minimum sampling time. Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules 52229 TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— Continued As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . 8. Stokers/sloped grate/ others designed to burn kiln-dried biomass fuel. 9. Fluidized bed units designed to burn biomass/bio-based solid. For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . b. Filterable PM (or TSM). 3.4E–02 lb per MMBtu of heat input; or (2.0E–04 lb per MMBtu of heat input). Collect a minimum of 2 dscm per run. a. CO ........................... 460 ppm by volume on a dry basis corrected to 3-percent oxygen. 4.0E–02 lb per MMBtu of steam output or 4.8E–01 lb per MWh; or (2.4E–04 lb per MMBtu of steam output or 2.8E–03 lb per MWh). 4.2E–01 lb per MMBtu of steam output or 5.1 lb per MWh. b. Filterable PM (or TSM). 3.2E–01 lb per MMBtu of heat input; or (5.0E–03 lb per MMBtu of heat input). Collect a minimum of 1 dscm per run. a. CO (or CEMS) ......... 210 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (310 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 2.1E–02 lb per MMBtu of heat input; or (6.4E–05 lb per MMBtu of heat input). 3.7E–01 lb per MMBtu of steam output or 4.5 lb per MWh; or (5.9E–03 lb per MMBtu of steam output or 7.0E–02 lb per MWh). 2.1E–01 lb per MMBtu of steam output or 2.3 lb per MWh; threerun average. b. Filterable PM (or TSM). 10. Suspension burners designed to burn biomass/bio-based solid. a. CO (or CEMS) ......... b. Filterable PM (or TSM). 11. Dutch Ovens/Pile burners designed to burn biomass/biobased solid. a. CO (or CEMS) ......... b. Filterable PM (or TSM). 12. Fuel cell units designed to burn biomass/bio-based solid. a. CO ........................... b. Filterable PM (or TSM). 13. Hybrid suspension grate units designed to burn biomass/biobased solid. a. CO (or CEMS) ......... b. Filterable PM (or TSM). jbell on DSKJLSW7X2PROD with PROPOSALS2 14. Units designed to burn liquid fuel. 15. Units designed to burn heavy liquid fuel. VerDate Sep<11>2014 2,400 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (2,000 ppm by volume on a dry basis corrected to 3-percent oxygen,c 10-day rolling average). 4.1E–02 lb per MMBtu of heat input; or (8.0E–03 lb per MMBtu of heat input). 770 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (520 ppm by volume on a dry basis corrected to 3-percent oxygen,c 10day rolling average). 1.8E–01 lb per MMBtu of heat input; or (2.0E–03 lb per MMBtu of heat input). 1,100 ppm by volume on a dry basis corrected to 3-percent oxygen. 2.0E–02 lb per MMBtu of heat input; or (5.8E–03 lb per MMBtu of heat input). 3,500 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (900 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30-day rolling average). 4.4E–01 lb per MMBtu of heat input; or (4.5E–04 lb per MMBtu of heat input). 2.6E–02 lb per MMBtu of steam output or 0.30 lb per MWh; or (8.0E–05 lb per MMBtu of steam output or 9.0E–04 lb per MWh). 1.9 lb per MMBtu of steam output or 27 lb per MWh; three-run average. 4.2E–02 lb per MMBtu of steam output or 5.8E–01 lb per MWh; or (8.1E–03 lb per MMBtu of steam output or 0.12 lb per MWh). 8.4E–01 lb per MMBtu of steam output or 8.4 lb per MWh; threerun average. 5.5E–01 lb per MMBtu of steam output or 6.2 lb per MWh; or (5.7E–04 lb per MMBtu of steam output or 6.3E–03 lb per MWh). 1.4E–03 lb per MMBtu of steam output or 1.6E–02 lb per MWh. per MMBtu of heat 8.8E–07 a lb per MMBtu of steam output or 1.1E–05 lb per MWh. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average. 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. Frm 00033 Fmt 4701 1 hr minimum sampling time. Collect a minimum of 2 dscm per run. 1 hr minimum sampling time. Collect a minimum of 2 dscm per run. 7.3E–07 input. PO 00000 Collect a minimum of 1 dscm per run. 5.5E–02 lb per MMBtu of steam output or 2.8E–01 lb per MWh; or (1.6E–02 lb per MMBtu of steam output or 8.1E–02 lb per MWh). 3.5 lb per MMBtu of steam output or 39 lb per MWh; three-run average. b. Mercury .................... Jkt 250001 1 hr minimum sampling time. Collect a minimum of 1 dscm per run. 1.1E–03 lb per MMBtu of heat input 18:10 Aug 21, 2020 1 hr minimum sampling time. 2.5E–01 lb per MMBtu of steam output or 2.6 lb per MWh; or (2.8E–03 lb per MMBtu of steam output or 2.8E–02 lb per MWh). 2.4 lb per MMBtu of steam output or 12 lb per MWh. a. HCl ........................... a lb Using this specified sampling volume or test run duration . . . Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time. 1 hr minimum sampling time. Collect a minimum of 1 dscm per run. For M26A, collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B collect a minimum sample as specified in the method, for ASTM D6784 b collect a minimum of 2 dscm. 1 hr minimum sampling time. 52230 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— Continued As stated in § 63.7500, you must comply with the following applicable emission limits: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . 16. Units designed to burn light liquid fuel. For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . b. Filterable PM (or TSM). 5.9E–02 lb per MMBtu of heat input; or (2.0E–04 lb per MMBtu of heat input). a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen. 7.9E–03 a lb per MMBtu of heat input; or (6.2E–05 lb per MMBtu of heat input). 7.2E–02 lb per MMBtu of steam output or 8.2E–01 lb per MWh; or (2.5E–04 lb per MMBtu of steam output or 2.8E–03 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh. 9.6E–03 a lb per MMBtu of steam output or 1.1E–01 a lb per MWh; or (7.5E–05 lb per MMBtu of steam output or 8.6E–04 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. b. Filterable PM (or TSM). 17. Units designed to burn liquid fuel that are non-continental units. a. CO ........................... b. Filterable PM (or TSM). 18. Units designed to burn gas 2 (other) gases. 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average based on stack test. 2.2E–01 lb per MMBtu of heat input; or (8.6E–04 lb per MMBtu of heat input). Using this specified sampling volume or test run duration . . . Collect a minimum of 1 dscm per run. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. 2.7E–01 lb per MMBtu of steam output or 3.1 lb per MWh; or (1.1E–03 lb per MMBtu of steam output or 1.2E–02 lb per MWh). 0.16 lb per MMBtu of steam output or 1.0 lb per MWh. Collect a minimum of 2 dscm per run. For M26A, collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 2 dscm. Collect a minimum of 3 dscm per run. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen. b. HCl ........................... 1.7E–03 lb per MMBtu of heat input 2.9E–03 lb per MMBtu of steam output or 1.8E–02 lb per MWh. c. Mercury .................... 7.9E–06 lb per MMBtu of heat input 1.4E–05 lb per MMBtu of steam output or 8.3E–05 lb per MWh. d. Filterable PM (or TSM). 7.3E–03 lb per MMBtu of heat input or (2.1E–04 lb per MMBtu of heat input). 1.3E–02 lb per MMBtu of steam output or 7.6E–02 lb per MWh; or (3.5E–04 lb per MMBtu of steam output or 2.2E–03 lb per MWh). 1 hr minimum sampling time. a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. c An owner or operator may request an alternative test method under § 63.7 of this chapter, in order that compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone injection, scrubber media, etc. d Before [date 3 years after date of publication of final rule in the Federal Register] you may comply with the emission limits in Table 15 to this subpart. On and after [date 3 years after date of publication of final rule in the Federal Register], you must comply with the emission limits in Table 2 to this subpart. ■ 18. Table 3 of subpart DDDDD is amended by revising the entry for ‘‘5.’’ and ‘‘6.’’ to read as follows: TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS As stated in § 63.7500, you must comply with the following applicable work practice standards: jbell on DSKJLSW7X2PROD with PROPOSALS2 If your unit is . . . You must meet the following . . . * * * * * * * 5. An existing or new boiler a. You must operate all CMS during startup. or process heater subject b. For startup of a boiler or process heater, you must use one or a combination of the following clean fuels: Natto emission limits in Table ural gas, synthetic natural gas, propane, other Gas 1 fuels, distillate oil, syngas, ultra-low sulfur diesel, fuel oil1 or 2 or 11 through 13 to soaked rags, kerosene, hydrogen, paper, cardboard, refinery gas, liquefied petroleum gas, clean dry biomass, this subpart during startup. and any fuels meeting the appropriate HCl, mercury and TSM emission standards by fuel analysis. c. You have the option of complying using either of the following work practice standards. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 52231 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS—Continued As stated in § 63.7500, you must comply with the following applicable work practice standards: If your unit is . . . You must meet the following . . . (1) If you choose to comply using definition (1) of ‘‘startup’’ in § 63.7575, once you start firing fuels that are not clean fuels you must vent emissions to the main stack(s) and engage all of the applicable control devices except limestone injection in fluidized bed combustion (FBC) boilers, dry scrubber, fabric filter, and selective catalytic reduction (SCR). You must start your limestone injection in FBC boilers, dry scrubber, fabric filter, and SCR systems as expeditiously as possible. Startup ends when steam or heat is supplied for any purpose, OR (2) If you choose to comply using definition (2) of ‘‘startup’’ in § 63.7575, once you start to feed fuels that are not clean fuels, you must vent emissions to the main stack(s) and engage all of the applicable control devices so as to comply with the emission limits within 4 hours of start of supplying useful thermal energy. You must engage and operate PM control within one hour of first feeding fuels that are not clean fuelsa. You must start all applicable control devices as expeditiously as possible, but, in any case, when necessary to comply with other standards applicable to the source by a permit limit or a rule other than this subpart that require operation of the control devices. You must develop and implement a written startup and shutdown plan, as specified in § 63.7505(e). d. You must comply with all applicable emission limits at all times except during startup and shutdown periods at which time you must meet this work practice. You must collect monitoring data during periods of startup, as specified in § 63.7535(b). You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.7555. You must operate all CMS during shutdown. While firing fuels that are not clean fuels during shutdown, you must vent emissions to the main stack(s) and operate all applicable control devices, except limestone injection in FBC boilers, dry scrubber, fabric filter, and SCR but, in any case, when necessary to comply with other standards applicable to the source that require operation of the control device. If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown process, that additional fuel must be one or a combination of the following clean fuels: Natural gas, synthetic natural gas, propane, other Gas 1 fuels, distillate oil, syngas, ultra-low sulfur diesel, refinery gas, and liquefied petroleum gas. You must comply with all applicable emissions limits at all times except for startup or shutdown periods conforming with this work practice. You must collect monitoring data during periods of shutdown, as specified in § 63.7535(b). You must keep records during periods of shutdown. You must provide reports concerning activities and periods of shutdown, as specified in § 63.7555. 6. An existing or new boiler or process heater subject to emission limits in Tables 1 or 2 or 11 through 15 to this subpart during shutdown. * * * * * 19. Table 4 to subpart DDDDD is amended by revising the column headings to read as follows: ■ TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS As stated in § 63.7500, you must comply with the applicable operating limits: When complying with a Table 1, 2, 11, 12, 13, 14, or 15 numerical emission limit using . . . * * * * * * * * 20. Table 7 to subpart DDDDD is amended by revising footnote ‘‘b’’ to read as follows: TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS a b jbell on DSKJLSW7X2PROD with PROPOSALS2 As stated in § 63.7520, you must comply with the following requirements for establishing operating limits: 18:10 Aug 21, 2020 Jkt 250001 * * * * ■ 21. Table 8 to subpart DDDDD is TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPER- amended by revising the entry for ‘‘8.’’ to read as follows: ATING LIMITS a b—Continued ■ VerDate Sep<11>2014 You must meet these operating limits . . . As stated in § 63.7520, you must comply with the following requirements for establishing operating limits: * * * * * b If you conduct multiple performance tests, you must set the minimum liquid flow rate and pressure drop operating limits at the higher of the minimum values established during the performance tests. For a minimum oxygen level, if you conduct multiple performance tests, you must set the minimum oxygen level at the lower of the minimum values established during the performance tests. For maximum operating load, if you conduct multiple performance tests, you must set the maximum operating load at the lower of the maximum values established during the performance tests. PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 52232 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE As stated in § 63.7540, you must show continuous compliance with the emission limitations for each boiler or process heater according to the following: If you must meet the following operating limits or work practice standards . . . * 8. Emission limits using fuel analysis. * * * You must demonstrate continuous compliance by . . . * * * * * * a. Conduct monthly fuel analysis for HCl or mercury or TSM according to Table 6 to this subpart; and b. Reduce the data to 12-month rolling averages; and c. Maintain the 12-month rolling average at or below the applicable emission limit for HCl or mercury or TSM in Tables 1 and 2 or 11 through 15 to this subpart. d. Calculate the HCI, mercury, and/or TSM emission rate from the boiler or process heater in units of lb/MMBtu using Equations 7, 8, and/or 9 in § 63.7530. * * * * * * * * * 22. Add Table 14 to subpart DDDDD of part 63 to read as follows: ■ TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS jbell on DSKJLSW7X2PROD with PROPOSALS2 As stated in § 63.7500, you may continue to comply with the following applicable emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . 1. Units in all subcategories designed to burn solid fuel. a. HCl ........................... 2.2E–02 lb per MMBtu of heat input 2.5E–02 lb per MMBtu of steam output or 0.28 lb per MWh. b. Mercury .................... 8.0E–07 input. per MMBtu of heat 8.7E–07 a lb per MMBtu of steam output or 1.1E–05 a lb per MWh. 2. Units designed to burn coal/solid fossil fuel. a. Filterable PM (or TSM). 1.1E–03 lb per MMBtu of heat input; or (2.3E–05 lb per MMBtu of heat input). 3. Pulverized coal boilers designed to burn coal/solid fossil fuel. a. Carbon monoxide (CO) (or CEMS). 4. Stokers/others designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 5. Fluidized bed units designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 6. Fluidized bed units with an integrated heat exchanger designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 7. Stokers/sloped grate/ others designed to burn wet biomass fuel. a. CO (or CEMS) ......... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (320 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (340 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (230 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 140 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (150 ppm by volume on a dry basis corrected to 3- percent oxygen,d 30day rolling average). 620 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (390 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 3.0E–02 lb per MMBtu of heat input; or (2.6E–05 lb per MMBtu of heat input). 1.1E–03 lb per MMBtu of steam output or 1.4E–02 lb per MWh; or (2.7E–05 lb per MMBtu of steam output or 2.9E–04 lb per MWh). 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. b. Filterable PM (or TSM). VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 PO 00000 a lb Frm 00036 Fmt 4701 Using this specified sampling volume or test run duration . . . For M26A, collect a minimum of 1 dscm per run; for M26 collect a minimum of 120 liters per run. For M29, collect a minimum of 4 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 4 dscm. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. 0.12 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 1.2E–01 lb per MMBtu of steam output or 1.5 lb per MWh; threerun average. 1 hr minimum sampling time. 5.8E–01 lb per MMBtu of steam output or 6.8 lb per MWh; threerun average. 1 hr minimum sampling time. 3.5E–02 lb per MMBtu of steam output or 4.2E–01 lb per MWh; or (2.7E–05 lb per MMBtu of steam output or 3.7E–04 lb per MWh). Collect a minimum of 2 dscm per run. Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules 52233 TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you may continue to comply with the following applicable emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . 8. Stokers/sloped grate/ others designed to burn kiln-dried biomass fuel. a. CO ........................... 460 ppm by volume on a dry basis corrected to 3-percent oxygen. 4.2E–01 lb per MMBtu of steam output or 5.1 lb per MWh. 1 hr minimum sampling time. b. Filterable PM (or TSM). 3.0E–02 lb per MMBtu of heat input; or (4.0E–03 lb per MMBtu of heat input). 3.5E–02 lb per MMBtu of steam output or 4.2E–01 lb per MWh; or (4.2E–03 lb per MMBtu of steam output or 5.6E–02 lb per MWh). 2.2E–01 lb per MMBtu of steam output or 2.6 lb per MWh; threerun average. Collect a minimum of 2 dscm per run. 9. Fluidized bed units a. CO (or CEMS) ......... designed to burn biomass/bio-based solids. b. Filterable PM (or TSM). 10. Suspension burners a. CO (or CEMS) ......... designed to burn biomass/bio-based solids. b. Filterable PM (or TSM). 11. Dutch Ovens/Pile burners designed to burn biomass/biobased solids. a. CO (or CEMS) ......... b. Filterable PM (or TSM). 2,400 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (2,000 ppm by volume on a dry basis corrected to 3-percent oxygen,d 10-day rolling average). 3.0E–02 lb per MMBtu of heat input; or (6.5E–03 lb per MMBtu of heat input). 330 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (520 ppm by volume on a dry basis corrected to 3-percent oxygen,d 10day rolling average). 3.2E–03 lb per MMBtu of heat input; or (3.9E–05 lb per MMBtu of heat input). 12. Fuel cell units dea. CO ........................... signed to burn biomass/bio-based solids. b. Filterable PM (or TSM). 910 ppm by volume on a dry basis corrected to 3-percent oxygen. 13. Hybrid suspension grate boiler designed to burn biomass/biobased solids. 1,100 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (900 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30-day rolling average). 2.6E–02 lb per MMBtu of heat input; or (4.4E–04 lb per MMBtu of heat input). a. CO (or CEMS) ......... b. Filterable PM (or TSM). 14. Units designed to burn liquid fuel. jbell on DSKJLSW7X2PROD with PROPOSALS2 230 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (310 ppm by volume on a dry basis corrected to 3-percent oxygen,d 30day rolling average). 9.8E–03 lb per MMBtu of heat input; or (8.3E–05 a lb per MMBtu of heat input). 15. Units designed to burn heavy liquid fuel. VerDate Sep<11>2014 Collect a minimum of 3 dscm per run. 3.1E–02 lb per MMBtu of steam output or 4.2E–01 lb per MWh; or (6.6E–03 lb per MMBtu of steam output or 9.1E–02 lb per MWh). 3.5E–01 lb per MMBtu of steam output or 3.6 lb per MWh; threerun average. Collect a minimum of 2 dscm per run. 3.0E–02 lb per MMBtu of steam output or 2.8E–01 lb per MWh; or (5.1E–05 lb per MMBtu of steam output or 4.1E–04 lb per MWh). 1.4 lb per MMBtu of steam output or 12 lb per MWh; three-run average. Collect a minimum of 2 dscm per run. 3.3E–02 lb per MMBtu of steam output or 3.7E–01 lb per MWh; or (5.5E–04 lb per MMBtu of steam output or 6.2E–03 lb per MWh). 4.8E–04 lb per MMBtu of steam output or 6.1E–03 lb per MWh. Collect a minimum of 3 dscm per run. 4.8E–07 input. per MMBtu of heat 5.3E–07 a lb per MMBtu of steam output or 6.7E–06 a lb per MWh. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average. 1.3E–02 lb per MMBtu of heat input; or (7.5E–05 lb per MMBtu of heat input). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1.5E–02 lb per MMBtu of steam output or 1.8E–01 lb per MWh; or (8.2E–05 lb per MMBtu of steam output or 1.1E–03 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh. 18:10 Aug 21, 2020 Jkt 250001 130 ppm by volume on a dry basis corrected to 3-percent oxygen. PO 00000 Frm 00037 Fmt 4701 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. b. Mercury .................... a. CO ........................... 1 hr minimum sampling time. 4.3E–03 lb per MMBtu of steam output or 4.5E–02 lb per MWh; or (5.2E–05 lb per MMBtu of steam output or 5.5E–04 lb per MWh). 1.1 lb per MMBtu of steam output or 1.0E+01 lb per MWh. 4.4E–04 lb per MMBtu of heat input a lb 1 hr minimum sampling time. 1.2E–02 lb per MMBtu of steam output or 0.14 lb per MWh; or (1.1E–04 a lb per MMBtu of steam output or 1.2E–03 a lb per MWh). 1.9 lb per MMBtu of steam output or 27 lb per MWh; three-run average. a. HCl ........................... b. Filterable PM (or TSM). 16. Units designed to burn light liquid fuel. 2.0E–02 lb per MMBtu of heat input; or (2.9E–05 a lb per MMBtu of heat input). Using this specified sampling volume or test run duration . . . Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time. 1 hr minimum sampling time. For M26A: Collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 4 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 4 dscm. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. 52234 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 14 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you may continue to comply with the following applicable emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . 17. Units designed to burn liquid fuel that are non-continental units. For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . Or the emissions must not exceed the following alternative outputbased limits, except during startup and shutdown . . . b. Filterable PM (or TSM). 1.1E–03 a lb per MMBtu of heat input; or (2.9E–05 lb per MMBtu of heat input). Collect a minimum of 3 dscm per run. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average based on stack test. 2.3E–02 lb per MMBtu of heat input; or (8.6E–04 lb per MMBtu of heat input). 1.2E–03 a lb per MMBtu of steam output or 1.6E–02 a lb per MWh; or (3.2E–05 lb per MMBtu of steam output or 4.0E–04 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 2.5E–02 lb per MMBtu of steam output or 3.2E–01 lb per MWh; or (9.4E–04 lb per MMBtu of steam output or 1.2E–02 lb per MWh). 0.16 lb per MMBtu of steam output or 1.0 lb per MWh. Collect a minimum of 4 dscm per run. For M26A, Collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 3 dscm. Collect a minimum of 3 dscm per run. b. Filterable PM (or TSM). 18. Units designed to burn gas 2 (other) gases. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen. b. HCl ........................... 1.7E–03 lb per MMBtu of heat input 2.9E–03 lb per MMBtu of steam output or 1.8E–02 lb per MWh. c. Mercury .................... 7.9E–06 lb per MMBtu of heat input 1.4E–05 lb per MMBtu of steam output or 8.3E–05 lb per MWh. d. Filterable PM (or TSM). 6.7E–03 lb per MMBtu of heat input; or (2.1E–04 lb per MMBtu of heat input). 1.2E–02 lb per MMBtu of steam output or 7.0E–02 lb per MWh; or (3.5E–04 lb per MMBtu of steam output or 2.2E–03 lb per MWh). Using this specified sampling volume or test run duration . . . 1 hr minimum sampling time. 1 hr minimum sampling time. 23. Add Table 15 to subpart DDDDD of part 63 to read as follows: ■ TABLE 15 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS jbell on DSKJLSW7X2PROD with PROPOSALS2 As stated in § 63.7500, you may continue to comply with following emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . 1. Units in all subcategories designed to burn solid fuel. a. HCl ........................... 2.2E–02 lb per MMBtu of heat input 2.5E–02 lb per MMBtu of steam output or 0.27 lb per MWh. b. Mercury .................... 5.7E–06 lb per MMBtu of heat input 6.4E–06 lb per MMBtu of steam output or 7.3E–05 lb per MWh. 2. Units design to burn coal/solid fossil fuel. a. Filterable PM (or TSM). 4.0E–02 lb per MMBtu of heat input; or (5.3E–05 lb per MMBtu of heat input). 3. Pulverized coal boilers designed to burn coal/solid fossil fuel. a. CO (or CEMS) ......... 4. Stokers/others designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (320 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 160 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (340 ppm by volume on a dry basis corrected to 3- percent oxygen,c 30day rolling average). 4.2E–02 lb per MMBtu of steam output or 4.9E–01 lb per MWh; or (5.6E–05 lb per MMBtu of steam output or 6.5E–04 lb per MWh). 0.11 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. VerDate Sep<11>2014 18:10 Aug 21, 2020 Jkt 250001 PO 00000 Frm 00038 Fmt 4701 0.14 lb per MMBtu of steam output or 1.7 lb per MWh; three-run average. Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 Using this specified sampling volume or test run duration . . . For M26A, Collect a minimum of 1 dscm per run; for M26, collect a minimum of 120 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 3 dscm. Collect a minimum of 2 dscm per run. 1 hr minimum sampling time. 1 hr minimum sampling time. Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules 52235 TABLE 15 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you may continue to comply with following emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . 5. Fluidized bed units designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 0.12 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 1 hr minimum sampling time. 6. Fluidized bed units with an integrated heat exchanger designed to burn coal/ solid fossil fuel. a. CO (or CEMS) ......... 1.3E–01 lb per MMBtu of steam output or 1.5 lb per MWh; threerun average. 1 hr minimum sampling time. 7. Stokers/sloped grate/ others designed to burn wet biomass fuel. a. CO (or CEMS) ......... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (230 ppm by volume on a dry basis corrected to 3- percent oxygen,c 30day rolling average). 140 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (150 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30day rolling average). 1,500 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (720 ppm by volume on a dry basis corrected to 3-percent oxygen,c 30-day rolling average). 3.7E–02 lb per MMBtu of heat input; or (2.4E–04 lb per MMBtu of heat input). 1.4 lb per MMBtu of steam output or 17 lb per MWh; three-run average. 1 hr minimum sampling time. 4.3E–02 lb per MMBtu of steam output or 5.2E–01 lb per MWh; or (2.8E–04 lb per MMBtu of steam output or 3.4E–04 lb per MWh). 4.2E–01 lb per MMBtu of steam output or 5.1 lb per MWh. Collect a minimum of 2 dscm per run. 3.7E–01 lb per MMBtu of steam output or 4.5 lb per MWh; or (4.6E–03 lb per MMBtu of steam output or 5.6E–02 lb per MWh). 4.6E–01 lb per MMBtu of steam output or 5.2 lb per MWh; threerun average. Collect a minimum of 1 dscm per run. b. Filterable PM (or TSM). 8. Stokers/sloped grate/ others designed to burn kiln-dried biomass fuel. 9. Fluidized bed units designed to burn biomass/bio-based solid. a. CO ........................... 460 ppm by volume on a dry basis corrected to 3-percent oxygen. b. Filterable PM (or TSM). 3.2E–01 lb per MMBtu of heat input; or (4.0E–03 lb per MMBtu of heat input). a. CO (or CEMS) ......... 470 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (310 ppm by volume on a dry basis corrected to 3- percent oxygen,c 30day rolling average). 1.1E–01 lb per MMBtu of heat input; or (1.2E–03 lb per MMBtu of heat input). b. Filterable PM (or TSM). 10. Suspension burners designed to burn biomass/bio-based solid. a. CO (or CEMS) ......... b. Filterable PM (or TSM). 11. Dutch Ovens/Pile burners designed to burn biomass/biobased solid. a. CO (or CEMS) ......... b. Filterable PM (or TSM). jbell on DSKJLSW7X2PROD with PROPOSALS2 12. Fuel cell units designed to burn biomass/bio-based solid. a. CO ........................... b. Filterable PM (or TSM). 13. Hybrid suspension grate units designed to burn biomass/biobased solid. VerDate Sep<11>2014 a. CO (or CEMS) ......... 18:10 Aug 21, 2020 Jkt 250001 2,400 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (2,000 ppm by volume on a dry basis corrected to 3-percent oxygen,c 10-day rolling average). 5.1E–02 lb per MMBtu of heat input; or (6.5E–03 lb per MMBtu of heat input). 770 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (520 ppm by volume on a dry basis corrected to 3-percent oxygen,c 10day rolling average). 2.8E–01 lb per MMBtu of heat input; or (2.0E–03 lb per MMBtu of heat input). 1,100 ppm by volume on a dry basis corrected to 3-percent oxygen. 2.0E–02 lb per MMBtu of heat input; or (5.8E–03 lb per MMBtu of heat input). 3,500 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average; or (900 ppm by volume on a dry basis corrected to 3- percent oxygen,c 30-day rolling average). PO 00000 Frm 00039 Fmt 4701 1.4E–01 lb per MMBtu of steam output or 1.6 lb per MWh; or (1.5E–03 lb per MMBtu of steam output or 1.7E–02 lb per MWh). 1.9 lb per MMBtu of steam output or 27 lb per MWh; three-run average. 5.2E–02 lb per MMBtu of steam output or 7.1E–01 lb per MWh; or (6.6E–03 lb per MMBtu of steam output or 9.1E–02 lb per MWh). 8.4E–01 lb per MMBtu of steam output or 8.4 lb per MWh; threerun average. Using this specified sampling volume or test run duration . . . 1 hr minimum sampling time. 1 hr minimum sampling time. Collect a minimum of 1 dscm per run. 1 hr minimum sampling time. Collect a minimum of 2 dscm per run. 1 hr minimum sampling time. 3.9E–01 lb per MMBtu of steam output or 3.9 lb per MWh; or (2.8E–03 lb per MMBtu of steam output or 2.8E–02 lb per MWh). 2.4 lb per MMBtu of steam output or 12 lb per MWh. Collect a minimum of 1 dscm per run. 5.5E–02 lb per MMBtu of steam output or 2.8E–01 lb per MWh; or (1.6E–02 lb per MMBtu of steam output or 8.1E–02 lb per MWh). 3.5 lb per MMBtu of steam output or 39 lb per MWh; three-run average. Collect a minimum of 2 dscm per run. Sfmt 4702 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time. 1 hr minimum sampling time. 52236 Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / Proposed Rules TABLE 15 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—Continued As stated in § 63.7500, you may continue to comply with following emission limits until [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu per hour or greater] If your boiler or process heater is in this subcategory . . . 14. Units designed to burn liquid fuel. 15. Units designed to burn heavy liquid fuel. For the following pollutants . . . The emissions must not exceed the following emission limits, except during startup and shutdown . . . The emissions must not exceed the following alternative output-based limits, except during startup and shutdown . . . b. Filterable PM (or TSM). 4.4E–01 lb per MMBtu of heat input; or (4.5E–04 lb per MMBtu of heat input). a. HCl ........................... 1.1E–03 lb per MMBtu of heat input 5.5E–01 lb per MMBtu of steam output or 6.2 lb per MWh; or (5.7E–04 lb per MMBtu of steam output or 6.3E–03 lb per MWh). 1.4E–03 lb per MMBtu of steam output or 1.6E–02 lb per MWh. b. Mercury .................... 2.0E–06 input. per MMBtu of heat 2.5E–06 a lb per MMBtu of steam output or 2.8E–05 lb per MWh. a. CO ........................... 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three-run average. 6.2E–02 lb per MMBtu of heat input; or (2.0E–04 lb per MMBtu of heat input). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. 7.5E–02 lb per MMBtu of steam output or 8.6E–01 lb per MWh; or (2.5E–04 lb per MMBtu of steam output or 2.8E–03 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh. 9.6E–03 a lb per MMBtu of steam output or 1.1E–01 a lb per MWh; or (7.5E–05 lb per MMBtu of steam output or 8.6E–04 lb per MWh). 0.13 lb per MMBtu of steam output or 1.4 lb per MWh; three-run average. b. Filterable PM (or TSM). 16. Units designed to burn light liquid fuel. a. CO ........................... b. Filterable PM (or TSM). 17. Units designed to burn liquid fuel that are non-continental units. a. CO ........................... b. Filterable PM (or TSM). 18. Units designed to burn gas 2 (other) gases. a lb 130 ppm by volume on a dry basis corrected to 3-percent oxygen. 7.9E–03 a lb per MMBtu of heat input; or (6.2E–05 lb per MMBtu of heat input). 130 ppm by volume on a dry basis corrected to 3-percent oxygen, three3-run average based on stack test. 2.7E–01 lb per MMBtu of heat input; or (8.6E–04 lb per MMBtu of heat input). b. HCl ........................... 1.7E–03 lb per MMBtu of heat input 2.9E–03 lb per MMBtu of steam output or 1.8E–02 lb per MWh. c. Mercury .................... 7.9E–06 lb per MMBtu of heat input 1.4E–05 lb per MMBtu of steam output or 8.3E–05 lb per MWh. d. Filterable PM (or TSM). 6.7E–03 lb per MMBtu of heat input or (2.1E–04 lb per MMBtu of heat input). 1.2E–02 lb per MMBtu of steam output or 7.0E–02 lb per MWh; or (3.5E–04 lb per MMBtu of steam output or 2.2E–03 lb per MWh). jbell on DSKJLSW7X2PROD with PROPOSALS2 BILLING CODE 6560–50–P PO 00000 Frm 00040 Fmt 4701 Collect a minimum of 1 dscm per run. 1 hr minimum sampling time. Collect a minimum of 3 dscm per run. 1 hr minimum sampling time. For M26A, collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B, collect a minimum sample as specified in the method; for ASTM D6784 b collect a minimum of 2 dscm. Collect a minimum of three dscm per run. 130 ppm by volume on a dry basis corrected to 3-percent oxygen. Jkt 250001 For M26A, collect a minimum of 2 dscm per run; for M26, collect a minimum of 240 liters per run. For M29, collect a minimum of 3 dscm per run; for M30A or M30B collect a minimum sample as specified in the method, for ASTM D6784 b collect a minimum of 2 dscm. 1 hr minimum sampling time. Collect a minimum of 2 dscm per run. a. CO ........................... 18:10 Aug 21, 2020 Collect a minimum of 1 dscm per run. 3.3E–01 lb per MMBtu of steam output or 3.8 lb per MWh; or (1.1E–03 lb per MMBtu of steam output or 1.2E–02 lb per MWh). 0.16 lb per MMBtu of steam output or 1.0 lb per MWh. [FR Doc. 2020–15121 Filed 8–21–20; 8:45 am] VerDate Sep<11>2014 Using this specified sampling volume or test run duration . . . Sfmt 9990 E:\FR\FM\24AUP2.SGM 24AUP2 1 hr minimum sampling time.

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 85, Number 164 (Monday, August 24, 2020)]
[Proposed Rules]
[Pages 52198-52236]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-15121]



[[Page 52197]]

Vol. 85

Monday,

No. 164

August 24, 2020

Part II





Environmental Protection Agency





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





40 CFR Part 63





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





National Emission Standards for Hazardous Air Pollutants for Major 
Sources: Industrial, Commercial, and Institutional Boilers and Process 
Heaters; Amendments; Proposed Rule

Federal Register / Vol. 85, No. 164 / Monday, August 24, 2020 / 
Proposed Rules

[[Page 52198]]


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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-10010-81-OAR]
RIN 2060-AU20


National Emission Standards for Hazardous Air Pollutants for 
Major Sources: Industrial, Commercial, and Institutional Boilers and 
Process Heaters; Amendments

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

SUMMARY: On January 31, 2013, the U.S. Environmental Protection Agency 
(EPA) finalized amendments to the national emission standards (NESHAP) 
for the control of hazardous air pollutants (HAP) at major sources from 
new and existing industrial, commercial, and institutional (ICI) 
boilers and process heaters. Subsequently, the United States Court of 
Appeals for the District of Columbia Circuit (D.C. Circuit), in a 
decision issued in July 2016, remanded several of the emission 
standards to the EPA based on the court's review of the EPA's approach 
to setting those standards. In response to these remands, this action 
proposes to amend several numeric emission limits for new and existing 
boilers and process heaters consistent with the court's opinion and set 
compliance dates for these new emission limits. The court also remanded 
for further explanation the Agency's use of carbon monoxide (CO) as a 
surrogate for organic HAP and, in a subsequent decision in March 2018, 
remanded for further explanation the Agency's use of a CO threshold to 
represent the application of the maximum achievable control technology 
(MACT) for organic HAP. The proposed changes to the emissions limits 
will protect air quality and promote public health by reducing 
emissions of the HAP listed in the Clean Air Act (CAA). This action 
also addresses the two issues remanded to the EPA for further 
explanation. We are also proposing several technical clarifications and 
corrections.

DATES: 
    Comments. Comments must be received on or before October 23, 2020. 
Under the Paperwork Reduction Act (PRA), comments on the information 
collection provisions are best assured of consideration if the Office 
of Management and Budget (OMB) receives a copy of your comments on or 
before September 23, 2020.
    Public hearing. If anyone contacts us requesting a public hearing 
on or before August 31, 2020, we will hold a virtual public hearing. 
See SUPPLEMENTARY INFORMATION for information on requesting and 
registering for a public hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2002-0058, by any of the following methods:
     Federal eRulemaking Portal: https://www.regulations.gov/ 
(our preferred method). Follow the online instructions for submitting 
comments.
     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2002-0058 in the subject line of the message.
    Instructions: All submissions received must include the Docket ID 
No. for this rulemaking. Comments received may be posted without change 
to https://www.regulations.gov/, including any personal information 
provided. For detailed instructions on sending comments and additional 
information on the rulemaking process, see the SUPPLEMENTARY 
INFORMATION section of this document. Out of an abundance of caution 
for members of the public and our staff, the EPA Docket Center and 
Reading Room was closed to public visitors on March 31, 2020, to reduce 
the risk of transmitting COVID-19. Our Docket Center staff will 
continue to provide remote customer service via email, phone, and 
webform. We encourage the public to submit comments via https://www.regulations.gov/ or email, as there is a temporary suspension of 
mail delivery to the EPA, and no hand deliveries are currently 
accepted. For further information on EPA Docket Center services and the 
current status, please visit us online at https://www.epa.gov/dockets.
    If requested, the virtual hearing will be held on September 8, 
2020. The hearing will convene at 9:00 a.m. Eastern Standard Time (EST) 
and will conclude at 3:00 p.m. EST. The EPA will announce further 
details on the virtual public hearing website at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters. Refer to the SUPPLEMENTARY 
INFORMATION section below for additional information.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed 
action, contact Mr. Jim Eddinger, 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) 541-5426; and email address: 
[email protected].

SUPPLEMENTARY INFORMATION: 
    Participation in virtual public hearing. Please note that the EPA 
is deviating from its typical approach because the President has 
declared a national emergency. Due to the current Centers for Disease 
Control and Prevention (CDC) recommendations, as well as state and 
local orders for social distancing to limit the spread of COVID-19, the 
EPA cannot hold in-person public meetings at this time.
    If a public hearing is requested, the EPA will begin pre-
registering speakers for the hearing upon publication of this document 
in the Federal Register. To register to speak at the virtual hearing, 
please use the online registration form available at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters or contact Ms. Adrian Gates 
at (919) 541-4860 or by email at [email protected] to register to 
speak at the virtual public hearing. The last day to pre-register to 
speak at the hearing will be September 8, 2020. On September 8, 2020, 
the EPA will post a general agenda for the hearing that will list pre-
registered speakers in approximate order at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters.
    The EPA will make every effort to follow the schedule as closely as 
possible on the day of the hearing; however, please plan for the 
hearing to run either ahead of schedule or behind schedule.
    Each commenter will have 5 minutes to provide oral testimony. The 
EPA encourages commenters to provide the EPA with a copy of their oral 
testimony electronically (via email) by emailing it to Jim Eddinger and 
Adrian Gates. The EPA also recommends submitting the text of your oral 
testimony as written comments to the rulemaking docket.
    The EPA may ask clarifying questions during the oral presentations 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral testimony and 
supporting information presented at the public hearing.
    Please note that any updates made to any aspect of the hearing will 
be posted online at https://www.epa.gov/stationary-sources-air-pollution/industrial-commercial-and-institutional-boilers-and-process-heaters. While the

[[Page 52199]]

EPA expects the hearing to go forward as set forth above, if requested, 
please monitor our website or contact Adrian Gates at 919-541-4862 or 
[email protected] to determine if there are any updates. The EPA 
does not intend to publish a document in the Federal Register 
announcing updates.
    If you require the services of a translator or a special 
accommodation such as audio description, please pre-register for the 
hearing with Adrian Gates and describe your needs by August 31, 2020. 
The EPA may not be able to arrange accommodations without advance 
notice.
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2002-0058. All documents in the docket are 
listed in Regulations.gov. Although listed, some information is not 
publicly available, e.g., Confidential Business Information (CBI) or 
other information whose disclosure is restricted by statute. Certain 
other material, such as copyrighted material, is not placed on the 
internet and will be publicly available only in hard copy. Publicly 
available docket materials are available electronically in 
Regulations.gov.
    Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2002-0058. The EPA's policy is that all comments received will be 
included in the public docket without change and may be made available 
online at https://www.regulations.gov/, including any personal 
information provided, unless the comment includes information claimed 
to be CBI or other information whose disclosure is restricted by 
statute. Do not submit electronically any information that you consider 
to be CBI or other information whose disclosure is restricted by 
statue. This type of information should be submitted by mail as 
discussed below.
    The EPA may publish any comment received to its public docket. 
Multimedia submissions (audio, video, etc.) must be accompanied by a 
written comment. The written comment is considered the official comment 
and should include discussion of all points you wish to make. The EPA 
will generally not consider comments or comment contents located 
outside of the primary submission (i.e., on the Web, cloud, or other 
file sharing system). For additional submission methods, the full EPA 
public comment policy, information about CBI or multimedia submissions, 
and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
    The https://www.regulations.gov/ website allows you to submit your 
comment anonymously, which means the EPA will not know your identity or 
contact information unless you provide it in the body of your comment. 
If you send an email comment directly to the EPA without going through 
https://www.regulations.gov/, your email address will be automatically 
captured and included as part of the comment that is placed in the 
public docket and made available on the internet. If you submit an 
electronic comment, the EPA recommends that you include your name and 
other contact information in the body of your comment and with any 
digital storage media you submit. If the EPA cannot read your comment 
due to technical difficulties and cannot contact you for clarification, 
the EPA may not be able to consider your comment. Electronic files 
should not include special characters or any form of encryption and be 
free of any defects or viruses. For additional information about the 
EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
    The EPA is temporarily suspending its Docket Center and Reading 
Room for public visitors to reduce the risk of transmitting COVID-19. 
Written comments submitted by mail are temporarily suspended and no 
hand deliveries will be accepted. Our Docket Center staff will continue 
to provide remote customer service via email, phone, and webform. We 
encourage the public to submit comments via https://www.regulations.gov/. For further information and updates on EPA Docket 
Center services, please visit us online at https://www.epa.gov/dockets.
    The EPA continues to carefully and continuously monitor information 
from the CDC, local area health departments, and our Federal partners 
so that we can respond rapidly as conditions change regarding COVID-19.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov/ or email. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
any digital storage media that you mail to the EPA, mark the outside of 
the digital storage media as CBI and then identify electronically 
within the digital storage media the specific information that is 
claimed as CBI. In addition to one complete version of the comments 
that includes information claimed as CBI, you must submit a copy of the 
comments that does not contain the information claimed as CBI directly 
to the public docket through the procedures outlined in Instructions 
above. If you submit any digital storage media that does not contain 
CBI, mark the outside of the digital storage media clearly that it does 
not contain CBI. Information not marked as CBI will be included in the 
public docket and the EPA's electronic public docket without prior 
notice. Information marked as CBI will not be disclosed except in 
accordance with procedures set forth in 40 Code of Federal Regulations 
(CFR) part 2. Send or deliver information identified as CBI only to the 
following address: OAQPS Document Control Officer (C404-02), OAQPS, 
U.S. Environmental Protection Agency, Research Triangle Park, North 
Carolina 27711, Attention: Docket ID No. EPA-HQ-OAR-2002-0058. Note 
that written comments containing CBI and submitted by mail may be 
delayed and no hand deliveries will be accepted.
    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
CEDRI Compliance and Emissions Data Reporting Interface
CBI Confidential Business Information
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO Carbon Monoxide
EPA Environmental Protection Agency
HAP hazardous air pollutant(s)
HCl hydrogen chloride
Hg mercury
ICI industrial, commercial, and institutional
lb/MMBtu pounds per million British thermal units
MACT maximum achievable control technology
MPCRF Multipollutant Control Research Facility
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PAH polycyclic aromatic hydrocarbons
PM particulate matter
ppb parts per billion
ppm parts per million
RDL representative detection level
tpy tons per year
TSM total selected metals
UPL upper prediction limit
VOC volatile organic compounds

    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?
II. Background

[[Page 52200]]

    A. What is the statutory authority for this action?
III. Discussion of the Proposed Amendments
    A. Revisions to MACT Floor Emission Limits
    B. Beyond-the-Floor Emission Limits
    C. Revisions to Output-Based Emission Limits
    D. Proposed Response to the Amended Issue: CO as a Surrogate for 
Organic HAP
    E. Proposed Response to the Amended Issue: CO 130 ppm Threshold 
Emission Limits
IV. Results and Proposed Decisions
    A. What are the resulting changes to emission limits?
    B. What compliance dates are we proposing?
    C. What other actions are we proposing?
V. Summary of Cost, Environmental, and Economic Impacts
    A. What are the affected sources?
    B. What are the air quality impacts?
    C. What are the cost impacts?
    D. What are the secondary impacts?
    E. What are the economic impacts?
    F. What are the benefits?
VI. Request for Comments
VII. 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

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action
a. Need for Regulatory Action
    The NESHAP for Industrial, Commercial, and Institutional Boilers 
and Process Heaters was promulgated on March 21, 2011, and amended on 
January 31, 2013, and November 20, 2015. Environmental groups and 
industry submitted petitions seeking judicial review of the NESHAP. On 
December 23, 2016, the D.C. Circuit amended its July 29, 2016 decision 
to remand instead of vacate certain emission standards where it held 
that the EPA had improperly excluded certain units in establishing the 
emission standards and remanded the use of CO as a surrogate for 
organic HAP for further explanation. In March 2018, the court in a 
separate case remanded the EPA's decision to set a limit of 130 parts 
per million (ppm) CO as a minimum standard for certain subcategories 
for further explanation. The courts did not set specific deadlines for 
the EPA to issue revised regulations as part of either remand.
    In response to these remands, the EPA is proposing to amend several 
emission standards consistent with the court's opinion and proposing 
responses to the two issues remanded for further explanation.
b. Legal Authority
    The statutory authority for this proposed rulemaking is section 112 
of the CAA. Title III of the CAA Amendments was enacted to reduce 
nationwide air toxic emissions. Section 112(d)(2) of the CAA directs 
the EPA to develop NESHAP which require existing and new major sources 
to control emissions of HAP using MACT based standards. This NESHAP 
applies to all ICI boilers and process heaters located at major sources 
of HAP emissions.\1\
---------------------------------------------------------------------------

    \1\ See 75 FR 32016 and section 63.7575 ``What definitions apply 
to this subpart'' of 40 CFR part 63, subpart DDDDD for definitions 
of ICI boilers and process heaters.
---------------------------------------------------------------------------

2. Summary of the Major Provisions of the Regulatory Action in Question
    The EPA is proposing to revise 34 different emission limits which 
it had previously promulgated in 2011 and amended in, 2013. Of these 34 
emission limits, 28 of the limits would become more stringent and six 
of the limits would become less stringent. EPA is also proposing that 
facilities would have up to 3 years after the effective date of the 
final rule to demonstrate compliance with these revised emission 
limits. A list of each combination of subcategory and pollutant where 
the limits have proposed revisions is shown in Table 1.

  Table 1--Summary of Subcategories With Proposed Revisions to Emission
                                 Limits
------------------------------------------------------------------------
                                             Pollutant where a limit is
                Subcategory                      proposed to change
------------------------------------------------------------------------
New-Solid.................................  HCl.
New-Dry Biomass Stoker....................  TSM.
New-Biomass Fluidized Bed.................  CO, PM, TSM.
New-Biomass Suspension Burner.............  CO, TSM.
New-Biomass Hybrid Suspension Grate.......  CO.
New-Biomass Dutch Oven/Pile Burner........  PM.
New-Biomass Dutch Oven/Pile Burner........  PM.
New-Biomass Dutch Oven/Pile Burner........  CO, PM.
New-Liquid................................  HCl.
New-Heavy Liquid..........................  PM, TSM.
New-Process Gas...........................  PM.
Existing-Solid............................  HCl, Hg.
Existing-Coal.............................  PM.
Existing-Coal Stoker......................  CO.
Existing-Dry Biomass Stoker...............  TSM.
Existing-Wet Biomass Stoker...............  CO, PM, TSM.
Existing-Biomass Fluidized Bed............  CO, PM, TSM.
Existing-Biomass Suspension Burners.......  PM, TSM.
Existing-Biomass Dutch Oven/Pile Burner...  PM.
Existing-Liquid...........................  Hg.
Existing-Heavy Liquid.....................  PM.
Existing-Non-continental Liquid...........  PM.
Existing-Process Gas......................  PM.
------------------------------------------------------------------------

3. Costs and Benefits
    We have estimated certain cost and benefits of the proposed rule, 
and these are found in Table 2. Present values (PV) of the net co-
benefits, in 2016 dollars and discounted to 2020, are from $655 million 
to $1,575 million when using a 7-percent discount rate and from $751 
million to $1,871 million when using a 3-percent discount rate. The 
equivalent annualized values (EAV) of the net co-benefits are from $78 
million to $194 million per year when using a 7-percent discount rate 
and from $92 million to $232 million per year when using a 3-percent 
discount rate. All of these estimates are in 2016 dollars. The 
monetized benefits estimate reflects an annual average of 251 tons of 
fine particulate matter (PM2.5) emission reductions per year 
and 393 tons of sulfur dioxide (SO2) emission reductions per 
year. These benefits are referred to as ancillary co-benefits since 
these pollutants are not targeted for control in the proposal. The 
unmonetized benefits include: Reduced exposure to HAP, including 
mercury (Hg), hydrochloric acid (HCl), non-Hg metals (e.g., antimony, 
cadmium), formaldehyde, benzene, and polycyclic

[[Page 52201]]

organic matter; reduced climate effects due to reduced black carbon 
emissions; reduced ecosystem effects; and reduced visibility 
impairments. We represent the present value of unmonetized benefits 
from affected HAP emission reductions as a C, and this is part of the 
net benefits estimate. We represent the equivalent annualized value of 
unmonetized benefits from affected HAP emission reductions as a D, and 
this is part of the net benefits estimate. These estimates also include 
climate co-disbenefits resulting from an increase in carbon dioxide 
(CO2) emissions, a secondary impact from electricity use by 
additional control devices in response to the proposal. This disbenefit 
is $0.09 million at a 3-percent discount rate and $0.01 million at a 7-
percent discount rate.
    More information on these impacts can be found in section V of this 
preamble and in the Regulatory Impact Analysis (RIA) for this proposal.

  Table 2--Summary of Present Values and Equivalent Annualized Values for Annual Costs, Monetized Ancillary Co-
         Benefits, and Monetized Net Benefits (Including Ancillary Co-Disbenefits) for the Proposed Rule
                                         [Millions of 2016 dollars] 1 2
----------------------------------------------------------------------------------------------------------------
                                                                  3% Discount rate          7% Discount rate
----------------------------------------------------------------------------------------------------------------
Present Value.......................  Targeted Benefits \3\.                         C                         C
                                     ---------------------------------------------------------------------------
                                      Ancillary Co-Benefits.           $730 to $1,650            $630 to $1,100
                                      Cost \4\..............                     $130                      $100
                                      Net Benefits \5\......        $600 to $1,520 + C        $530 to $1,000 + C
----------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value.........  Targeted Benefits \6\.                        D                         D
                                      Ancillary Co-Benefits.              $100 to 240                $90 to 180
                                     ---------------------------------------------------------------------------
                                      Costs.................                       18                        17
                                      Net Benefits..........           $80 to 220 + D            $70 to 160 + D
----------------------------------------------------------------------------------------------------------------
\1\ All estimates in this table are rounded to one decimal point, so numbers may not sum due to independent
  rounding.
\2\ All estimates reflect the amendments to the ICI Boilers MACT standard included in this proposal from a
  baseline that includes the control technologies applied to meet the MACT standard.
\3\ C represents the present value of unquantified benefits from reductions in targeted HAP emissions.
\4\ The annualized present value of costs and benefits are calculated over an 8-year period from 2021 to 2028.
\5\ The total monetized ancillary co-benefits reflect the human health benefits associated with reducing
  exposure to PM2.5 through reductions of directly emitted PM2.5 and SO2. Monetized ancillary co-benefits
  include many, but not all, health effects associated with PM2.5 exposure. Co-benefits are shown as a range
  from Krewski et al. (2009) to Lepeule et al. (2012). We do not report the total monetized ancillary co-
  benefits by PM2.5 species. The ancillary climate co-disbenefits from additional CO2 emissions resulting from
  control device operations are included in the results given the rounding convention employed in this table as
  stated in footnote a. The net benefits calculation consists of the targeted benefits and ancillary co-benefits
  minus the social costs.
\6\ D represents the equivalent annualized value of unquantified benefits from reductions in targeted HAP
  emissions.

B. Does this action apply to me?

    Table 3 of this preamble lists the NESHAP and associated regulated 
industrial source categories that are the subject of this proposal. 
Table 3 is not intended to be exhaustive, but rather provides a guide 
for readers regarding the entities that this proposed action is likely 
to affect. The proposed standards, once promulgated, will be directly 
applicable to the affected sources. As defined in the Initial List of 
Categories of Sources Under Section 112(c)(1) of the Clean Air Act 
Amendments of 1990 (see 57 FR 31576, July 16, 1992) and Documentation 
for Developing the Initial Source Category List, Final Report (see EPA-
450/3-91-030, July 1992), the Industrial Boiler source category 
includes boilers used in manufacturing, processing, mining, and 
refining or any other industry to provide steam, hot water, and/or 
electricity. The Institutional/Commercial Boilers source category 
includes, but is not limited to, boilers used in commercial 
establishments, medical centers, research centers, institutions of 
higher education, hotels, and laundries to provide electricity, steam, 
and/or hot water. Waste heat boilers are excluded from this definition. 
The Process Heaters source category includes, but is not limited to, 
secondary metals process heaters, petroleum and chemical industry 
process heaters, and other process heaters. A process heater is defined 
as an enclosed device using controlled flame, and the unit's primary 
purpose is to transfer heat indirectly to a process material (liquid, 
gas, or solid) or to a heat transfer material (e.g., glycol or a 
mixture of glycol and water) for use in a process unit, instead of 
generating steam. Process heaters do not include units used for comfort 
heat or space heat, food preparation for on-site consumption, or 
autoclaves. Waste heat process heaters are excluded from this 
definition. A boiler or process heater combusting solid waste is not a 
boiler unless the device is exempt from the definition of a solid waste 
incineration unit as provided in section 129(g)(1) of the CAA.

[[Page 52202]]



                           Table 3--Source Categories Affected by This Proposed Action
----------------------------------------------------------------------------------------------------------------
                                                                    NAICS code 1      Examples of potentially
            Source category                       NESHAP                                 regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or process  Industrial, Commercial,               211  Extractors of crude petroleum
 heater as defined in the final rule.    and Institutional                          and natural gas.
                                         Boilers and Process
                                         Heaters..
                                        .........................             321  Manufacturers of lumber and
                                                                                    wood products.
                                        .........................             322  Pulp and paper mills.
                                        .........................             325  Chemical manufacturers.
                                        .........................             324  Petroleum refineries, and
                                                                                    manufacturers of coal
                                                                                    products.
                                        .........................   316, 326, 339  Manufacturers of rubber and
                                                                                    miscellaneous plastic
                                                                                    products.
                                        .........................             331  Steel works, blast furnaces.
                                        .........................             332  Electroplating, plating,
                                                                                    polishing, anodizing, and
                                                                                    coloring.
                                        .........................             336  Manufacturers of motor
                                                                                    vehicle parts and
                                                                                    accessories.
                                        .........................             221  Electric, gas, and sanitary
                                                                                    services.
                                        .........................             622  Health services.
                                        .........................             611  Educational services.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.

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 proposed action at 
https://www.epa.gov/industrial-commercial-and-institutional-boilers-and-process-heaters. Following publication in the Federal Register, the 
EPA will post the Federal Register version of the proposal and key 
technical documents at this same website.
    A redline version of the regulatory language that incorporates the 
proposed changes in this action is available in the docket for this 
action (Docket ID No. EPA-HQ-OAR-2002-0058).

II. Background

    On March 21, 2011, the EPA established final emission standards for 
ICI boilers and process heaters at major sources, reflecting the 
application of MACT--the Boiler MACT (76 FR 15608). On January 31, 
2013, the EPA promulgated final amendments to the Boiler MACT (78 FR 
7138). On November 20, 2015, the EPA promulgated additional amendments 
to the Boiler MACT (80 FR 72789) in response to certain reconsideration 
issues, but other issues remained unresolved due to pending litigation 
at the time these final amendments were published.
    On July 29, 2016, the D.C. Circuit issued its decision in U.S. 
Sugar Corp v. EPA, 830 F.3d 579. In that decision, the court upheld the 
EPA's 2013 Boiler MACT against all challenges brought by industry 
petitioners, and virtually all challenges brought by environmental 
petitioners. However, the court vacated the MACT floor emission limits 
for those subcategories where the EPA had excluded certain units from 
its MACT-floor calculation because those units burned less than 90 
percent of the subcategory defining fuel. U. S. Sugar Corp. v. EPA, 830 
F.3d at 631. On December 23, 2016, the D.C. Circuit granted EPA's 
motion for rehearing on remedy and remanded without vacatur these 
affected MACT standards. 844 F.3d 268. Therefore, these MACT standards 
have remained in effect since the court's decision.
    Additionally, the court in U.S. Sugar remanded the use of CO as a 
surrogate for non-dioxin organic HAP to the EPA for the limited purpose 
of addressing the potential availability of post-combustion control 
technologies that could control CO. In a subsequent decision on March 
16, 2018, the D.C. Circuit remanded the EPA's decision to set a limit 
of 130 ppm CO as a surrogate for non-dioxin organic HAP for certain 
subcategories, again asking the Agency to better explain its analysis 
supporting its decision. Sierra Club v. EPA, 884 F.3d 1185.
    In this action, the EPA is proposing changes to certain emissions 
limits in the final rule and is providing additional explanation of 
certain issues relating to the CO standards in response to these 
remands. The EPA is also proposing several technical corrections.

A. What is the statutory authority for this action?

    Section 112 of the CAA establishes a regulatory process to address 
emissions of HAP from stationary sources. CAA section 112(d) requires 
the Agency to promulgate technology-based NESHAP for major sources. 
``Major sources'' are defined in CAA Section 112(a) as sources that 
emit or have the potential to emit 10 tons or more per year (tpy) of a 
single HAP or 25 tpy or more of any combination of HAP. For major 
sources, the technology-based NESHAP must require the maximum degree of 
reduction in emissions of HAP achievable (after considering cost, 
energy requirements, and non-air quality health and environmental 
impacts). These standards are commonly referred to as MACT standards.
    The MACT ``floor'' is the minimum control level allowed for MACT 
standards promulgated under CAA section 112(d)(3) and may not be based 
on cost considerations. For new sources, the MACT floor cannot be less 
stringent than the emissions control that is achieved in practice by 
the best controlled similar source. The MACT floor for existing sources 
may be less stringent than floors for new sources but may not be less 
stringent than the average emissions limitation achieved by the best-
performing 12 percent of existing sources in the category or 
subcategory (or the best-performing five sources for categories or 
subcategories with fewer than 30 sources). In developing MACT 
standards, the EPA must also consider control options that are more 
stringent than the floor (i.e., ``beyond-the-floor'' options) under CAA 
section 112(d)(2). We may establish beyond-the-floor standards more 
stringent than the floor based on considerations of the cost of 
achieving the emission reductions, any non-air quality health and 
environmental impacts, and energy requirements.

[[Page 52203]]

III. Discussion of the Proposed Amendments

A. Revisions to MACT Floor Emission Limits

1. Revisions to MACT Floor Ranking Methodology for Co-Fired Units
    Many of the affected sources subject to numerical limits under the 
NESHAP involve boilers and process heaters that co-fire multiple fuel 
types. In the January 2013 final rule amendments, the EPA defined each 
subcategory using a threshold of at least 10 percent of a subcategory-
defining fuel, on an annual heat input basis. These definitions were 
set up in a hierarchical manner. Solid fuel units must burn at least 
10-percent solid fuel. Coal and solid fossil fuel units must burn at 
least 10-percent coal or another solid fossil fuel. Biomass units must 
burn at least 10-percent biomass, but less than 10-percent coal. Liquid 
fuel units may burn any liquid fuel but less than 10-percent coal or 
fossil solid, and less than 10-percent biomass. The MACT floor analysis 
conducted in the 2013 rulemaking used a 90-percent fuel threshold, 
instead of the regulatory definition of 10 percent, to group test data 
into subcategories for ranking the best performers and calculating the 
MACT floors. This approach excluded several units that were in the 
subcategory from the ranking analysis, which in turn excluded these 
boilers from consideration in upper prediction limit (UPL) calculations 
to establish the MACT floor.
    The D.C. Circuit in U.S. Sugar stated that, if EPA includes a 
source in a subcategory, it must consider whether any source in that 
subcategory is a best-performing source which would then need to be 
accounted for in setting the MACT floor. U.S. Sugar v. EPA, 830 F.3d at 
631. Following the EPA's request for rehearing, the court remanded 
standards affected by its decision to the EPA for further 
consideration, and the EPA is now proposing to revise the affected 
standards consistent with the court's opinion.
    For this proposal, the same dataset used as the basis for the 2013 
final rule was used as the basis of the calculations for the proposed 
revised standards.\2\ The EPA performed a more detailed review of the 
units in the dataset that had previously been excluded from the 
rankings, with emphasis on the newly identified best performers. While 
checking background test reports, the EPA corrected some database 
errors, filled information gaps for certain co-fired fuel blends, and 
adjusted CO instrument span measurements. However, since the proposed 
revisions are solely to address the remand in U.S. Sugar, we re-ran the 
MACT floor analysis to incorporate data that had been previously 
excluded. The rankings of each subcategory were revised to incorporate 
data from tests that fired at least 10 percent of a subcategory-
defining fuel. This change in criteria impacted the number of units 
with emission test data for certain subcategories. In many cases test 
data for co-fired units in the 2013 Emissions Database did not quantify 
the exact fuel input breakdown.\3\ The EPA reviewed test reports that 
were included as background data materials for the 2013 Emissions 
Database and conducted outreach with selected facilities in order to 
verify to which subcategory the various test data belonged. Appendix B 
of the docketed memorandum, Revised MACT Floor Analysis (2019) for the 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants--Major Source 
(2019 MACT Floor Memo), details the revised ranking of each subcategory 
and compares the ranking to the previous ranking assignment from the 
January 2013 final rule. As was done in the January 2013 final rule, 
devices that were co-firing solid waste materials were excluded from 
the ranking unless the device was exempted from the definition of a 
solid waste incineration unit as provided in section 129(g)(1) of the 
CAA.
---------------------------------------------------------------------------

    \2\ Emissions Database for Boilers and Process Heaters 
Containing Stack Test, CEM, and Fuel Analysis Data Reporting under 
ICR No. 2286.01 and ICR No.2286.03 (OMB Control Number 2060-0616) 
(version 8). Docket ID No. EPA-HQ-OAR-2002-0058-3830.
    \3\ Ibid.
---------------------------------------------------------------------------

    As part of the revisions to the ranking analysis, the EPA also made 
corrections to some of the emissions data, as part of its data quality 
review of the revised set of best performing units in each subcategory. 
The EPA investigated historical notes in the 2013 Emissions Database 
about whether certain test results were valid or were previously 
excluded due to data quality concerns. When historical notes had 
excluded data, those exclusions were carried forward into the revised 
analysis supporting the proposal. Because some new best performing 
units were identified in the ranking analysis, the EPA also reviewed 
test reports that were available in the rulemaking docket to verify 
reported emission results in the database as well as oxygen adjustment 
factors, and CO instrument span and CO calibration data. EPA made 
corrections to the values used in the MACT floor analysis when these 
back-up documents suggested a correction was needed. In addition to 
data available from the docketed data resources, the EPA also received 
data correction files and a small number of additional tests from 
members of the American Forest and Paper Association. The EPA reviewed 
the additional data provided, including any supporting emission test 
reports to evaluate if the data were accurate and complete and 
representative prior to including the data in the revised ranking 
analysis. A summary of data changes made since version 8 of the 
database is available in the docketed memorandum, Summary of 2019 
Emission Database Changes for Major Source Boilers and Process Heaters. 
In addition, a summary of the expected impacts of these data changes is 
available in the Regulatory Impact Analysis for the Proposed ICI 
Boilers NESHAP Reconsideration, which is available in the docket for 
this action. The changes include an increase in compliance costs as 
well as an increase in emission reductions as a result of the more 
stringent emission limits.
a. Existing Sources
    Because the rankings shifted dramatically, the number of units in 
each of the subcategories changed, as well as the specific units that 
comprised the top 12 percent within the subcategory. Appendix B-1 of 
the 2019 MACT Floor Memo summarizes the revised number of units in the 
top 12 percent for each combination of subcategory and pollutant. The 
remainder of the worksheets in Appendix B indicate which units are 
identified to be among the top 12 percent.
    Once the top 12 percent of units were identified, each unique 
combination of pollutant and subcategory data was reviewed to determine 
the distribution of the dataset and then calculate the UPL. The 
procedures for determining the data distribution and calculating the 
UPL remain the same as they did for the January 2013 final rule, with 
the exception of ``limited datasets'' which are those that consisted of 
less than seven test runs. The procedures for determining the 
distribution and calculating the UPL are detailed in EPA's Response to 
Remand of the Record for Major Source Boilers, July 14, 2014 available 
in the docket for this action. Additional considerations for limited 
datasets are discussed in section III.A.2 of this preamble. The actual 
calculations and distribution assignments for each pollutant and 
subcategory combination are shown in

[[Page 52204]]

Appendix C of the 2019 MACT Floor Memo. The EPA is not soliciting 
comment on its use of the same methodology that it used to set the 
January 2013 standards, but is soliciting comment on the proposed 
revisions to the standards the Agency is proposing to address 
concerning the court's remand in U.S. Sugar.
    Once the UPL values were calculated, the EPA reviewed whether any 
additional fuel variability factors were available to multiply by the 
calculated UPL for Hg, HCl, and total selected metals \4\ (TSM). The 
methodology for computing the fuel variability factor did not change 
since the January 2013 final rule. Instead, any changes in the fuel 
variability factors occurred because of changes to the units that 
constituted the top 12 percent for each subcategory and were, 
therefore, eligible for consideration in the fuel variability factor 
analysis. The fuel variability factor calculations are shown in 
Appendix A of the 2019 MACT Floor Memo. Fuel variability factors were 
available for solid and liquid fuel subcategories for Hg and HCl and 
for biomass fluidized bed, coal, and heavy liquid subcategories for 
TSM.
---------------------------------------------------------------------------

    \4\ Total selected metals is the sum of the non-Hg HAP metals--
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel, and 
selenium.
---------------------------------------------------------------------------

b. New Sources
    Similar to existing sources, the re-ranking of the data for each 
new source subcategory impacted the specific units that were identified 
as the lowest emitting for each combination of pollutant and 
subcategory.
    Additionally, as in the January 2013 final rule, the EPA did not 
allow units with a nitrogen oxides-to-CO ratio above 50 to represent a 
best performing boiler for CO. Instead, the EPA picked the next lowest 
ranked unit for the Coal Stokers. Additionally, as in the January 2013 
final rule, the EPA only considered units with at least three test runs 
to serve as the basis of the new source floor except for cases where no 
other data were available. This occurred only for the TSM UPL 
calculations for new Biomass Suspension Burner. In that case, the 
second ranked unit was selected. The revisions to the emissions 
standards proposed here are for the limited purpose of addressing the 
court's remand in U.S. Sugar, and the EPA is not proposing or 
soliciting comment on other aspects of the standards or methodology 
used to calculate the standards.
    Once the best controlled similar source for each subcategory was 
identified, each unique combination of pollutant and subcategory data 
was reviewed to determine the distribution of the dataset and then 
calculate the UPL. The procedures for determining the data distribution 
and calculating the UPL remain the same as for the January 2013 final 
rule, with the exception of limited datasets that consisted of less 
than seven test runs or in cases where the calculated new source UPL 
exceeded the existing source UPL for the same subcategory. The 
procedures for determining the distribution and calculating the UPL are 
detailed in the docketed memorandum, Revised MACT Floor Analysis (2019) 
for the Industrial, Commercial, and Institutional Boilers and Process 
Heaters National Emission Standards for Hazardous Air Pollutants--Major 
Source. Many of the new source UPL calculations involved limited 
datasets and additional considerations for limited datasets are 
discussed in section III.A.2 of this preamble. The actual calculations 
and distribution assignments for each pollutant and subcategory 
combination are shown in Appendix E of the 2019 MACT Floor Memo. This 
appendix worksheet for each UPL calculation also shows the ranking of 
each unit.
    Once the UPL values were calculated, the EPA reviewed whether any 
additional fuel variability factors were available to multiply by the 
calculated UPL for Hg, HCl, and TSM. The methodology for computing the 
fuel variability factor did not change since the January 2013 final 
rule. Instead, any changes in the fuel variability factors occurred 
because of changes to the unit selected to represent the best 
controlled similar source and were, therefore, eligible for 
consideration in the fuel variability factor analysis for new sources. 
The fuel variability factor calculations are shown in Appendix A of the 
2019 MACT Floor Memo. Fuel variability factors were available for 
liquid fuel and coal subcategories for Hg and HCl, and the heavy liquid 
subcategory for TSM.
    The EPA also incorporated the same procedures as the January 2013 
final rule to ensure that the available measurement methods would 
provide accurate emissions measurements at the levels set for the 
various standards. The procedures are discussed in detail at 76 FR 
80611 and the calculated values are presented in technical memoranda in 
the docket.\5\ The procedures remained the same, but which unit 
represents the new source floor did change since January 2013; so, the 
actual representative detection level (RDL) calculation accordingly 
changed as well. The revised calculations for 3 times the RDL are 
presented in the documented memorandum. After computing the RDL, the 
UPL calculations were compared to a value equal to 3 times the RDL. In 
the case of new sources, if the UPL was below the 3 times RDL value 
then the MACT floor was set equal to 3 times the RDL.
---------------------------------------------------------------------------

    \5\ See Docket ID Item Nos.: EPA-HQ-OAR-2002-0058-3837 and EPA-
HQ-OAR-2002-0058-3839.
---------------------------------------------------------------------------

    Lastly, the EPA compared the calculated UPL, or 3 times RDL values 
where appropriate, to the existing source emission limits for the same 
pollutant and subcategory. If the new source floor was larger than the 
existing source floor, the EPA reviewed the data further as discussed 
in the UPL methodology for limited datasets in section III.A.2 of this 
preamble to evaluate if the unit truly reflected the best controlled 
similar source as determined by the Administrator and to evaluate if 
the UPL calculations required any adjustments to ensure that the UPL 
did not result in a less stringent standard for new sources. In 
addition to the tests conducted on limited datasets, two subcategories 
for new source limits required additional evaluation, as discussed 
below. Specific names of the facility and boiler names refer to how the 
boilers are identified in the MACT floor analysis to allow the reader 
to find these units in the related technical support memoranda.
    The MACT floor dataset for particulate matter (PM) from new 
fluidized bed boilers designed to burn biomass includes 18 test runs 
from a single boiler ``ORGeorgiaPacificWaunaMill, EU35--Fluidized Bed 
Boiler'' (EU35) that we identified as the best performing unit based on 
average emissions. The calculated UPL for new sources exceeded the UPL 
calculated for existing units in the same subcategory. After 
determining the correct distribution and ensuring that we used the 
correct equation for the distribution, we evaluated the variance of 
this unit. Our analysis showed that this unit, identified as the best 
performing unit based on average emissions, has a variance that is 3 
orders of magnitude higher than the second ranked unit 
``WIGPGreenBay2818, B10--Wastepaper Sludge-Fired Boiler 10'' (B10) and 
an overall average (considering all stack tests, not just the minimum 
stack test average) that is approximately 4 times higher than the 
second ranked unit. This information indicates that the second ranked 
unit, B10, has a more consistent level of performance than the top 
ranked unit, EU35, and the resulting UPL calculations support this. The 
calculated UPL is lower for the second ranked unit, B10, than for the 
top

[[Page 52205]]

ranked unit, EU35. For these reasons, we determined that the unit with 
the lowest average, EU35, is not the best performing source for this 
subcategory and pollutant and we are instead identifying B10 as the 
best performing source.
    The MACT floor dataset for PM from new stoker boilers designed to 
burn wet biomass includes nine test runs from a single boiler 
``IAMonsantoMuscatine, Boiler #8 EP-195'' that we identified as the 
best performing unit based on average emissions. The calculated UPL for 
new sources exceeded the UPL calculated for existing units in the same 
subcategory. The UPL based on a lognormal equation was 10.2 times 
higher than the mean. After reviewing the distribution of the dataset, 
we found that the distribution was incorrectly flagged as lognormally 
distributed instead of normally distributed. The UPL based on the 
normal distribution no longer exceeds the UPL calculation for existing 
sources. The UPL based on a normal equation was 2.36 times higher than 
the mean. After correcting the distribution, we also evaluated the 
variance of this unit, which was 4 times lower than the variance of the 
next lowest ranked unit. For these reasons, we determined that the UPL 
based on the normal distribution was the appropriate basis for the new 
source floor for this subcategory.
2. UPL Methodology for Limited Datasets
    In August 2013, the D.C. Circuit issued its decision in National 
Ass'n. of Clean Water Agencies (NACWA) v. EPA, which addressed 
challenges to the EPA's 2011 Sewage Sludge Incinerator (SSI) rule, 
issued under section 129 of the CAA. In NACWA v. EPA, the court 
remanded the EPA's use of the UPL methodology to the Agency for further 
explanation of how the methodology reflected the average emissions 
limitation achieved by the best-performing 12 percent of sources (for 
existing sources) and the average emissions limitation achieved by the 
best-performing similar source (for new sources). NACWA v. EPA, 734 
F.3d 1115, 1151. Because the UPL methodology used in the SSI rule was 
the same as that used in the major source Boiler MACT, the EPA 
requested a remand of the record in U.S. Sugar v. EPA in order to 
address the court's decision in NACWA v. EPA. The EPA prepared a 
memorandum explaining the methodology for the UPL. This memorandum, 
EPA's Response to Remand of the Record for Major Source Boilers, 
provides a detailed rationale to use the UPL as the basis of setting a 
MACT floor for new and existing sources, and the methodology and the 
explanation in the memorandum were upheld by the D.C. Circuit in U.S. 
Sugar v. EPA. 830 F.3d at 639. Following the UPL memorandum, the EPA 
issued a subsequent memorandum specifically addressing the application 
of the UPL methodology when setting MACT emission limits with limited 
datasets, Approach for Applying the Upper Prediction Limit to Limited 
Datasets. In that memorandum, the EPA concluded that there are 
additional considerations when setting MACT floors for limited 
datasets. The EPA is not, in this action, proposing any revisions to or 
soliciting comment on either the EPA's Response to Remand of the Record 
for Major Source Boilers memorandum or the limited datasets memorandum. 
Rather, the EPA is proposing limited revisions to certain Boiler MACT 
standards to address the specific issue remanded to the Agency by the 
court in U.S. Sugar v. EPA. The docketed memorandum, Approach for 
Applying the Upper Prediction Limit to Limited Datasets for Boilers and 
Process Heaters at Major Sources, discusses the generic methods in the 
previously issued limited dataset memorandum, as well as a summary of 
the findings for certain boiler and process heater subcategories. A 
summary of those findings is also discussed here.
    For the ICI Boilers and Process Heaters source categories, we have 
limited datasets for the following subcategories and pollutants for 
both existing and new sources: process gas (Hg, HCl, TSM, and PM), 
biomass suspension burner (TSM), dry biomass stoker (TSM, PM, and CO), 
and coal fluidized bed coal refuse (CO). For the ICI Boilers and 
Process Heaters source categories, we have limited datasets for the 
following subcategories and pollutants for new sources: Solid (Hg and 
HCl), liquid (Hg and HCl), heavy liquid (TSM and PM), light liquid (TSM 
and PM), biomass dutch oven/pile burner (TSM), biomass fuel cell (TSM), 
biomass fluidized bed (TSM), biomass suspension burner (TSM), biomass 
suspension grate (CO), wet biomass stoker (TSM), and coal (TSM and PM). 
Therefore, we evaluated these specific datasets to determine whether it 
is appropriate to make any modifications to the UPL approach used to 
calculate the MACT floors. For each dataset, we performed the following 
steps: Selected the data distribution that best represents the dataset; 
ensured that the correct equation for the distribution was then applied 
to the data; and compared individual components of the limited dataset 
to determine if the standards based on the limited dataset reasonably 
represent the performance of the units included in the dataset. The 
results of the limited dataset analyses are presented below for each 
subcategory and pollutant.
    The MACT floor datasets for Hg, HCl, and PM from existing and new 
boilers designed to burn process gas include three test runs from a 
single boiler. In addition, there are no other process gas units in the 
rankings to select from for these pollutants. Using the available data, 
we first determined the correct distribution and ensured that we used 
the correct equation for each distribution. The MACT floor dataset for 
TSM from existing and new boilers designed to burn process gas only 
includes two test runs. We assumed a distribution of lognormal for this 
dataset. We then calculated the UPL-based limits which range from 1.2 
to 3 times the average (mean) of all test runs from the best performing 
source. This result indicates that the emission limits are not 
unreasonable compared to the actual performance of the unit upon which 
the limits are based and are within the ranges that we see when we 
evaluate larger datasets using our MACT floor calculation procedures. 
Therefore, we determined that the emission limit reasonably accounts 
for variability and that no changes to the standard floor calculation 
procedure were warranted for this pollutant and subcategory.
    The MACT floor dataset for TSM from existing and new suspension 
burner boilers designed to burn biomass includes three test runs from a 
single boiler that we identified as the best performing unit based on 
average emissions. In addition, there are no other biomass suspension 
burner units in the rankings to select from for this pollutant because 
the other unit with test data only has two test runs, and units with 
less than three test runs were not considered for UPL calculations if 
other data are available (see discussion in section III.A.1 of this 
preamble). Using the available data, we first determined the correct 
distribution and ensured that we used the correct equation for each 
distribution. We then calculated the UPL-based limit which is 1.7 times 
the short-term average emissions from the best performing source. This 
result indicates that the emission limit is not unreasonable compared 
to the actual performance of the unit upon which the limit is based and 
is within the range that we see when we evaluate larger datasets using 
our MACT floor calculation procedures. Therefore, we determined that 
the emission limit reasonably accounts for

[[Page 52206]]

variability and that no changes to the standard floor calculation 
procedure were warranted for this pollutant and subcategory.
    The MACT floor dataset for TSM from existing and new stoker boilers 
designed to burn dry biomass includes three test runs from a single 
boiler. In addition, there are no other dry biomass stoker units in the 
rankings to select from for this pollutant. Using the available data, 
we first determined the correct distribution and ensured that we used 
the correct equation for each distribution. We then calculated the UPL-
based-limit, which is approximately 2 times the short-term average 
emissions from the best performing source, indicating that the emission 
limit is not unreasonable compared to the actual performance of the 
unit upon which the limit is based and is within the range that we see 
when we evaluate larger datasets using our MACT floor calculation 
procedures. Therefore, we determined that the emission limit reasonably 
accounts for variability and that no changes to the standard floor 
calculation procedure were warranted for this pollutant and 
subcategory.
    The MACT floor datasets for PM and CO from existing and new stoker 
boilers designed to burn dry biomass include three test runs from a 
single boiler that we identified as the best performing unit based on 
average emissions. After determining the correct distribution and 
ensuring that we used the correct equation for each distribution, we 
evaluated the variance of this unit for each pollutant, comparing it to 
other boilers in the same subcategory. Our analysis showed that this 
unit, identified as the best performing unit based on average 
emissions, also had the lowest variance for each pollutant, indicating 
that not only did it have the lowest average emissions but also the 
most consistent performance. Therefore, we determined that the emission 
limits reasonably account for variability and that no changes to our 
standard floor calculation procedure were warranted for this 
subcategory and pollutants.
    The MACT floor dataset for CO from existing and new fluidized bed 
boilers designed to burn coal refuse includes three test runs from a 
single boiler. In addition, there are no other units in the rankings to 
select from for this pollutant. Using the available data, we first 
determined the correct distribution and ensured that we used the 
correct equation for the distribution. We then calculated the UPL-based 
limit which is approximately 1.5 times the short-term average emissions 
from the best performing source, indicating that the emission limit is 
not unreasonable compared to the actual performance of the unit upon 
which the limit is based and is within the range that we see when we 
evaluate larger datasets using our MACT floor calculation procedures. 
Therefore, we determined that the emission limit reasonably accounts 
for variability and that no changes to the standard floor calculation 
procedure were warranted for this pollutant and subcategory.
    The MACT floor dataset for Hg from new boilers designed to burn 
solid fuel includes six test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for each distribution, we evaluated the variance 
of this unit, comparing it to other boilers in the same subcategory. 
Our analysis showed that this unit, identified as the best performing 
unit based on average emissions, also had the lowest variance, 
indicating that not only did it have the lowest average emissions but 
also the most consistent performance. Therefore, we determined that the 
emission limit reasonably accounts for variability and that no changes 
to our standard floor calculation procedure were warranted for this 
subcategory and pollutant.
    The MACT floor dataset for HCl from new boilers designed to burn 
solid fuel includes six test runs from a single boiler 
``ARPotlatchForestWarren, Wellons Boiler'' (Wellons Boiler) that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for each distribution, we compared the calculated 
UPL to the short-term average emissions and found that the unit had a 
UPL that was 81 times higher than the lowest short-term average 
emission test and that this ratio is not within the range that we see 
when we evaluate larger datasets using our MACT floor calculation 
procedures. Based on this, we evaluated the variance of this unit and 
concluded that further consideration of the best performer selection 
was warranted. The variance of the top ranked unit was 6 orders of 
magnitude higher than the variance of the next ranked unit 
``TXDibollTemple-Inland, PB-44'' (PB-44). In addition, the Wellons 
Boiler six test runs were from two separate stack tests, and while the 
unit was the top ranked unit due to one of the stack test averages 
being very low, the other stack test average was 6.2 times higher. The 
high degree of variance in the dataset for the unit with the lowest 
average, Wellons Boiler, prompted us to question whether this unit was, 
in fact, the best performing unit and to evaluate the dataset for PB-
44. The dataset for PB-44 includes three test runs and the average 
emissions are only about 7 percent higher than the Wellons Boiler 
lowest stack test average. However, the PB-44 average emissions are 
actually 97 percent lower when comparing to the Wellons Boiler average 
for both stack tests. This information indicates that the second ranked 
unit, PB-44, has a more consistent level of performance than the top 
ranked unit, Wellons Boiler, and the resulting UPL calculations support 
this. The HCl UPL value is lower for PB-44 than for Wellons Boiler and 
the Wellons Boiler UPL exceeded the UPL for existing solid fuel 
boilers. For these reasons, we determined that the unit with the lowest 
average, Wellons Boiler, is not the best performing source for this 
pollutant and we are instead determining PB-44 to be the best 
performing source.
    The MACT floor dataset for Hg from new boilers designed to burn 
liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for each distribution, we evaluated the variance 
of this unit. Our analysis showed that this unit, identified as the 
best performing unit based on average emissions, and the second ranked 
unit both have similar and extremely low variance, indicating 
consistent performance. Therefore, we determined that the emission 
limit reasonably accounts for variability and that no changes to the 
standard floor calculation procedure were warranted for this 
subcategory and pollutant.
    The MACT floor dataset for HCl from new boilers designed to burn 
liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for each distribution, we evaluated the variance 
of this unit, comparing it to other boilers in the same subcategory. 
Our analysis showed that this unit, identified as the best performing 
unit based on average emissions, also had the lowest variance, 
indicating that not only did it have the lowest average emissions but 
also the most consistent performance. Therefore, we determined that the 
emission limit reasonably accounts for variability and that no changes 
to the standard floor calculation procedure were warranted for this 
subcategory and pollutant.
    The MACT floor dataset for TSM from new boilers designed to burn 
heavy

[[Page 52207]]

liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for the distribution, we evaluated the variance of 
this unit, comparing it to other boilers in the same subcategory. Our 
analysis showed that this unit, identified as the best unit based on 
average emissions, had a slightly higher variance than the next ranked 
unit. Therefore, we also evaluated the second ranked unit and 
determined its distribution and applied the equation for its 
distribution. Comparing the calculated UPL values for the top two 
units, the best performing unit resulted in the lower UPL. While its 
variance was slightly higher, the top ranked unit's lower overall 
emissions and resulting UPL calculations indicate it is the best 
performer. Therefore, we determined that the emission limit reasonably 
accounts for variability and that no changes to the standard floor 
calculation procedure were warranted for this pollutant and 
subcategory.
    The MACT floor dataset for PM from new boilers designed to burn 
heavy liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for the distribution, we evaluated the variance of 
this unit, comparing it to other boilers in the same subcategory. Our 
analysis showed that this unit, identified as the best performing unit 
based on average emissions, also had the lowest variance, indicating 
that not only did it have the lowest average emissions but also the 
most consistent performance. Therefore, we determined that the emission 
limit reasonably accounts for variability and that no changes to the 
standard floor calculation procedure were warranted for this pollutant 
and subcategory.
    The MACT floor dataset for TSM from new boilers designed to burn 
light liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for the distribution, we evaluated the variance of 
this unit, comparing it to other boilers in the same subcategory. Our 
analysis showed that this unit, identified as the best performing unit 
based on average emissions, and the second ranked unit have nearly 
equivalent variance, indicating consistent performance. Therefore, we 
determined that the emission limit reasonably accounts for variability 
and that no changes to the standard floor calculation procedure were 
warranted for this pollutant and subcategory.
    The MACT floor dataset for PM from new boilers designed to burn 
light liquid fuel includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for the distribution, we evaluated the variance of 
this unit, comparing it to other boilers in the same subcategory. Our 
analysis showed that this unit, identified as the best performing unit 
based on average emissions, also had the lowest variance, indicating 
that not only did it have the lowest average emissions but also the 
most consistent performance. Therefore, we determined that the emission 
limit reasonably accounts for variability and that no changes to the 
standard floor calculation procedure were warranted for this pollutant 
and subcategory.
    The MACT floor dataset for TSM from new dutch oven boilers designed 
to burn biomass includes three test runs from a single boiler that we 
identified as the best performing unit based on average emissions. 
After determining the correct distribution and ensuring that we used 
the correct equation for the distribution, we evaluated the variance of 
this unit, comparing it to other boilers in the same subcategory. Our 
analysis showed that this unit, identified as the best performing unit 
based on average emissions, also had the lowest variance, indicating 
that not only did it have the lowest average emissions but also the 
most consistent performance. Therefore, we determined that the emission 
limit reasonably accounts for variability and that no changes to the 
standard floor calculation procedure were warranted for this pollutant 
and subcategory.
    The MACT floor dataset for TSM from new biomass fuel cell boilers 
includes six test runs from a single boiler that we identified as the 
best performing unit based on average emissions. After determining the 
correct distribution and ensuring that we used the correct equation for 
the distribution, we evaluated the variance of this unit, comparing it 
to other boilers in the same subcategory. Our analysis showed that this 
unit, identified as the best performing unit based on average 
emissions, also had the lowest variance, indicating that not only did 
it have the lowest average emissions but also the most consistent 
performance. Therefore, we determined that the emission limit 
reasonably accounts for variability and that no changes to the standard 
floor calculation procedure were warranted for this pollutant and 
subcategory.
    The MACT floor dataset for TSM from new fluidized bed boilers 
designed to burn biomass includes three test runs from a single boiler 
that we identified as the best performing unit based on average 
emissions. After determining the correct distribution and ensuring that 
we used the correct equation for the distribution, we evaluated the 
variance of this unit, comparing it to other boilers in the same 
subcategory. Our analysis showed that this unit, identified as the best 
performing unit based on average emissions, also had the lowest 
variance, indicating that not only did it have the lowest average 
emissions but also the most consistent performance. Therefore, we 
determined that the emission limit reasonably accounts for variability 
and that no changes to the standard floor calculation procedure were 
warranted for this pollutant and subcategory.
    The MACT floor dataset for TSM from new suspension burners designed 
to burn biomass includes three test runs from a single boiler. In 
addition, there are no other biomass suspension burner units in the 
rankings to select from for this pollutant. Using the available data, 
we first determined the correct distribution and ensured that we used 
the correct equation for each distribution. We then calculated the UPL-
based limit which is 1.7 times the short-term average emissions from 
the best performing source, indicating that the emission limit is not 
unreasonable compared to the actual performance of the unit upon which 
the limit is based and is within the range that we see when we evaluate 
larger datasets using our MACT floor calculation procedures. Therefore, 
we determined that the emission limit reasonably accounts for 
variability and that no changes to our standard floor calculation 
procedure were warranted for this subcategory and pollutant.
    The MACT floor dataset for TSM from new stoker boilers designed to 
burn wet biomass includes six test runs from a single boiler 
``GAGPCelluloseBrunswick, U700--No. 4 Power Boiler'' (U700--No. 4 Power 
Boiler) that we identified as the best performing unit based on average 
emissions. After determining the correct distribution and ensuring that 
we used the correct equation for the distribution, we evaluated the 
variance of this unit, comparing it to other boilers in the same 
subcategory. We note that the second and third ranked units each have 
less than three test runs, and units with less than three test runs 
were not considered for UPL calculations if other data are available 
(see discussion in section

[[Page 52208]]

III.A.1 of this preamble). Our analysis showed that this unit, 
identified as the best performing unit based only on average emissions, 
has a higher variance than the fourth ranked unit ``MESDWarrenSomerset, 
No. 2 Power Boiler'' (No. 2 Power Boiler) and an overall average 
(considering all stack tests, not just the minimum stack test average) 
that is approximately 18 percent higher than the fourth ranked unit. 
This information indicates that the fourth ranked unit, No. 2 Power 
Boiler, has a more consistent level of performance than the top ranked 
unit, U700--No. 4 Power Boiler, and the resulting UPL calculations 
support this. The calculated UPL is lower for the fourth ranked unit, 
No. 2 Power Boiler, than for the top ranked unit, U700--No. 4 Power 
Boiler. For these reasons, we determined that the unit with the lowest 
average, U700--No. 4 Power Boiler, is not the best performing source 
for this subcategory and pollutant and we are instead determining that 
No. 2 Power Boiler is the best performing source.
    The MACT floor dataset for CO from new suspension grate boilers 
designed to burn biomass includes three test runs from a single boiler 
that we identified as the best performing unit based on average 
emissions. After determining the correct distribution and ensuring that 
we used the correct equation for each distribution, we evaluated the 
variance of this unit, comparing it to other boilers in the same 
subcategory. Our analysis showed that this unit, identified as the best 
unit based on average emissions, also had the lowest variance, 
indicating that not only did it have the lowest average emissions but 
also the most consistent performance. Therefore, we determined that the 
emission limit reasonably accounts for variability and that no changes 
to the standard floor calculation procedure were warranted for this 
subcategory and pollutant.
    The MACT floor dataset for TSM from new coal boilers includes six 
test runs from a single boiler that we identified as the best 
performing unit based on average emissions. After determining the 
correct distribution and ensuring that we used the correct equation for 
each distribution, we evaluated the variance of this unit and concluded 
that further consideration of the best performer selection was 
warranted. The variance of the top ranked unit was approximately 3 
times higher than the variance of the next ranked unit. The degree of 
variance in the dataset for the unit with the lowest average prompted 
us to question whether this unit was, in fact, the best performing unit 
and to evaluate the second ranked unit. The second ranked unit includes 
3 test runs. We calculated the UPL using data for the second ranked 
unit, however, and the resulting UPL was higher than when using data 
from the top ranked unit. While its variance was higher, the top ranked 
unit's lower overall emissions and resulting UPL calculations indicate 
it is the best performer. Therefore, we determined that the emission 
limit reasonably accounts for variability and that no changes to the 
standard floor calculation procedure were warranted for this 
subcategory and pollutant.
    The MACT floor dataset for PM from new coal boilers includes six 
test runs from a single boiler that we identified as the best 
performing unit based on average emissions. After determining the 
correct distribution and ensuring that we used the correct equation for 
each distribution, we evaluated the variance of this unit and concluded 
that further consideration of the best performer selection was 
warranted. The variance of the top ranked unit was approximately 2.5 
times higher than the variance of the next ranked unit. The degree of 
variance in the dataset for the unit with the lowest average prompted 
us to question whether this unit was, in fact, the best performing unit 
and to evaluate the second ranked unit. The second ranked unit includes 
three test runs. We calculated the UPL using data for the second ranked 
unit, however, and the resulting UPL was higher than when using data 
from the top ranked unit. Therefore, while its variance was higher, the 
top ranked unit's lower overall emissions and resulting UPL 
calculations indicate it is the best performer. Therefore, we 
determined that the emission limit reasonably accounts for variability 
and that no changes to the standard floor calculation procedure were 
warranted for this subcategory and pollutant.
    The Process Gas and Coal Fluidized Bed subcategories for existing 
and new sources and the Heavy Liquid Fuel, Light Liquid Fuel, 
Pulverized Coal Boilers, and Coal Stoker subcategories for new sources 
have limited datasets for CO. However, the best performers have very 
low CO emissions and the emission limits were set equal to a minimum CO 
level; the applicable methodology is discussed in section III.E of this 
preamble.

B. Beyond-the-Floor Emission Limits

    We reviewed the recalculated MACT floor emission limits that are 
less stringent than those in the January 2013 final rule in order to 
assess whether a beyond-the-floor option was technically achievable and 
cost-effective. To assess whether the January 2013 limits were 
technically achievable we reviewed the compliance data available to the 
EPA through the Compliance and Emissions Data Reporting Interface 
(CEDRI) and WebFIRE \6\ and compared these data to the emission limits 
in the January 2013 final rule to assess whether those more stringent 
limits were being achieved in practice. Data is submitted to CEDRI by 
regulated entities to EPA in order to meet electronic reporting 
requirements of 40 CFR part 60 subpart DDDDD. These reports include 
performance tests, CEMS relative accuracy test audits, notifications of 
compliance status reports, among other items. WebFIRE displays these 
reports to the public and can be searched by regulatory subpart or 
boiler process type (e.g., fuel type, boiler size). For existing 
sources, with the exception of TSM at coal units, all of the compliance 
data available for the subcategory showed that the units were complying 
with the more stringent 2013 emission limit. For TSM at coal-fired 
units, 83 percent of the units (10 of 12) with data were below the more 
stringent 2013 emission limit. The two units that were not were 12 
percent above the 2013 emission limit, but these units were using the 
emission averaging provision to comply at a common stack. To assess 
whether the limits were cost-effective, the EPA reviewed the control 
devices currently installed to determine if any cost savings would 
occur should the less stringent limit be selected. In all of these 
cases, the controls that were already installed were the same types of 
controls that would be required to meet either the January 2013 limits 
or the less stringent recalculated limits and, therefore, no additional 
costs would be incurred to meet the more stringent limits. There were 
three additional cases where the January 2013 remanded emission limit 
was more stringent than the recalculated emission limit, but no recent 
compliance data were available in these three cases. Since no data were 
available for PM at Gas 2 units, and TSM at biomass suspension burners 
or dry biomass stokers, the EPA did not select a beyond-the-floor limit 
for these three emission limits. In all three of these cases, where we 
did not have data, the changes are resulting from the revised 
methodology for limited datasets. The process gas unit is uncontrolled, 
and the dry biomass stoker and biomass suspension burner both had a 
multiclone installed.
---------------------------------------------------------------------------

    \6\ U.S. Environmental Protection Agency. Compliance and 
Emissions Data Reporting Interface (CEDRI) https://www.epa.gov/electronic-reporting-air-emissions/cedri and WebFIRE database 
https://www.epa.gov/electronic-reporting-air-emissions/webfire.

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

[[Page 52209]]

    Based on the review of compliance data, the EPA selected a beyond-
the-floor level for 10 of the existing source emission limits, as 
listed in Table 4.

   Table 4--Existing Source Emission Limits Based on Beyond-the-Floor
------------------------------------------------------------------------
 Existing source subcategory
            limit                              Discussion
------------------------------------------------------------------------
HCl-Liquid...................  All of the existing units with data
                                available are below the 2013 emission
                                limit.
TSM-Coal.....................  All 10 of the existing units complying
                                with the TSM limit were below the 2013
                                emission limit.
TSM-Heavy Liquid.............  The two existing units with data were
                                both below the 2013 emission limit.
TSM-Light Liquid.............  The two existing units with data were
                                both below the 2013 emission limit.
PM-Dry Biomass Stoker........  All six of the existing units with data
                                were below the 2013 limit.
CO-Biomass Suspension Burner.  All 12 of the existing units with data
                                were below the 2013 limit.
CO-Biomass Suspension Grate..  All 99 of the existing units with data
                                were below the 2013 limit.
CO-Dry Biomass Stoker........  All six of the existing units with data
                                were below the 2013 limit.
CO-Coal Fluidized Bed with     The one existing unit with data was below
 Heat Exchanger.                the 2013 limit.
------------------------------------------------------------------------

    For new sources, the EPA made a similar comparison to compliance 
data from new and existing boilers in order to assess whether the 
limits were achievable. In addition, for PM emission limits at new 
sources, consistent with the analysis taken during the January 2013 
final rule, PM emission limits were compared to the PM limit of 0.03 
pound per million British thermal units (lb/MMBtu) for new biomass 
boilers in 40 CFR part 60, subparts Db and Dc. Only biomass compliance 
data were available for new sources, and so the EPA compared both 
existing and new source compliance data, when available, to the 
emission limits in the January 2013 final rule. For three of the 
limits, all of the units with available compliance data were below the 
more stringent January 2013 emission limit. For the PM limit at dry 
biomass stokers, and the TSM limit at wet biomass stokers, all of the 
available new source compliance data were meeting the more stringent 
January 2013 emission limit. Two of the limits had no new source data 
available for comparison, but the TSM at coal units had 50 percent of 
the existing units with data below the January 2013 new source limit, 
and 9 percent of the coal units were below the new source limit for PM. 
Both of these cases demonstrate that the limits are technically 
achievable. There were three cases where the January 2013 remanded new 
source emission limit was more stringent than the emission limit 
calculated based on the revised MACT floor calculation methodology, but 
no recent compliance data were available in these four cases. These 
were the same three groups mentioned for existing sources, PM at Gas 2 
units, and TSM at biomass suspension burners or dry biomass stokers. 
Due to lack of data, the EPA did not select a beyond-the-floor limit 
for these three emission limits. For new sources, there were seven 
emission limits where a beyond-the-floor level was selected, as listed 
in Table 5.

      Table 5--New Source Emission Limits Based On Beyond-the-Floor
------------------------------------------------------------------------
 New source subcategory limit                  Discussion
------------------------------------------------------------------------
TSM-Wet Biomass Stoker.......  Only one existing and one new wet stoker
                                boiler has TSM compliance data. The new
                                source data is below the 2013 new source
                                limit.
TSM-Coal.....................  Six of the 12 existing units with
                                compliance data are below the 2013 limit
                                for new sources. Of the ones that were
                                above the limit, all of them were above
                                both the 2013 limit and the remanded
                                MACT floor emission limit. No new coal
                                units were identified in recent
                                compliance data.
PM-Suspension Burner.........  The calculated UPL is identical to the
                                value calculated in the 2013 final rule
                                for existing sources. However, the UPL
                                calculation was less stringent than the
                                new source performance standards (NSPS)
                                limit for new boilers. Additionally, all
                                of the 13 units with PM test data are
                                below the 2013 limit for new sources.
PM-Dry Biomass Stoker........  Of the seven units with PM test data,
                                three units were below the 2013 emission
                                limits for new sources, including one
                                new dry biomass stoker boiler.
                                Additionally, the UPL calculation was
                                less stringent than the NSPS limit for
                                new boilers.
PM-Coal......................  Of the 101 existing units with PM test
                                data, nine units were below the 2013
                                emission limit for new sources. No new
                                coal units were identified in recent
                                compliance data.
CO-Dry Biomass Stoker........  All seven of the existing units with
                                data, including one new dry biomass
                                stoker were below the 2013 limit.
CO-Coal Fluidized Bed with     The one existing unit with data was below
 Heat Exchanger.                the 2013 limit.
------------------------------------------------------------------------

C. Revisions to Output-Based Emission Limits

    The EPA reviewed the output-based emission limits, and revised as 
necessary, for subcategories and pollutants where the input-based 
emission limits were revised. There was not a corresponding revision in 
the output-based emission limit for certain subcategories and 
pollutants where the input-based emission limit was revised, due to 
rounding (i.e., the input-based emission limit revision was small 
enough that performing the output-based calculations did not result in 
a different emission limit after rounding to two significant figures). 
We also updated the output-based emission limit calculations to use 
data from the current population of best performers, considering the 
changes to the rankings made in response to the court remands. 
Specifically, we revised the steam conversion factor (steam Btu out/
fuel Btu in) used to calculate the output-based limits in the units of 
lb/MMBtu steam output for three subcategories for existing sources: 
Biomass dutch oven, wet biomass, and coal stoker. We reviewed the 
corresponding steam conversion factors for new sources, but revisions 
were not necessary as a result of the new analyses. The memorandum,

[[Page 52210]]

Alternate Equivalent Output-Based Emission Limits for Boilers and 
Process Heaters Located at Major Source Facilities--2019 Revision, 
which is available in the docket for this action, provides details of 
the output-based emission limit revisions and methodology.

D. Proposed Response to the Amended Issue: CO as a Surrogate for 
Organic HAP

    On July 29, 2016, the D.C. Circuit remanded to the EPA to address a 
public comment relating to the potential availability of alternative 
control technologies which reduce organic HAP without impacting CO 
emissions. In doing so, the court rejected challengers' argument that 
the EPA could not use CO as a surrogate for non-dioxin/furan (D/F) 
organic HAP and limited its remand to the Agency's failure to address 
evidence in the record on the potential availability of alternative 
control technologies. The court further noted that ``it is likely'' 
that the EPA would be able to adequately explain its use of CO on 
remand. U.S. Sugar v. EPA, 830 F.3d at 630.
    It is helpful to provide some background on the EPA's decision to 
use CO as a surrogate in the Boiler MACT rule in order to provide the 
context for the EPA's action to address the U.S. Sugar court's remand 
for explanation. In the preamble to the June 2010 proposal, we 
presented the rationale for using CO as a surrogate for non-D/F organic 
HAP emitted from boilers and process heaters. We stated that CO has 
generally been used as a surrogate for organic HAP because CO is a good 
indicator of incomplete combustion and organic HAP are products of 
incomplete combustion. However, based on concerns that CO may not be an 
appropriate surrogate for D/F because, unlike other organic HAP, D/F 
can be formed outside the combustion unit, we proposed using CO as a 
surrogate only for non-D/F organic HAP. For non-D/F organic HAP, we 
concluded that using CO as a surrogate was a reasonable approach 
because minimizing CO emissions will result in minimizing non-D/F 
organic HAP. We stated that, for boilers and process heaters, methods 
used for the control of CO emissions would be the same methods used to 
control non-D/F organic HAP emissions. These emission control methods 
include achieving good combustion or using an oxidation catalyst. 
Standards limiting emissions of CO will also result in decreases in 
non-D/F organic HAP emissions (with the additional benefit of 
decreasing volatile organic compounds (VOC) emissions). Establishing 
emission limits for specific organic HAP would be impractical and 
costly. Thus, we concluded that CO, which is less expensive to test for 
and monitor, is appropriate for use as a surrogate for non-dioxin 
organic HAP.
    We stated in the 2010 proposal that we recognized that the level 
and distribution of organic HAP will vary from unit to unit. For 
example, the principal organic HAP emitted from coal-fired units is 
benzene, which accounts for about 20 percent of the organic HAP with 
formaldehyde accounting for about 4 percent of the organic HAP. 
Whereas, the principal organic HAP emitted from biomass-fired units is 
formaldehyde, which accounts for 34 percent of the organic HAP with 
benzene accounting for about 25 percent of the organic HAP.\7\ For oil-
fired units, formaldehyde is the principal organic HAP, accounting for 
about 80 percent of the organic HAP. Limiting CO as a surrogate for 
only non-dioxin organic HAP would eliminate costs associated with 
speciating numerous compounds. We also stated that CO was preferable 
because many sources currently have CO continuous emission monitoring 
systems (CEMS).
---------------------------------------------------------------------------

    \7\ Based on emission factors reported on the EPA web page, AP 
42, Fifth Edition, Volume 1--Chapter 1: External Combustion Sources, 
located at https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf.
---------------------------------------------------------------------------

    In the 2013 final rule preamble, as part of the rationale for the 
130 ppm CO minimum MACT floor level, we again explained the basis for 
concluding that CO is an appropriate surrogate. That is, CO is a 
conservative surrogate for organic HAP because organic HAP emissions 
are extremely low when sources operate under the good combustion 
conditions required to achieve low CO levels. There are myriad factors 
that affect combustion efficiency (CE) and, as a function of CE, CO 
emissions. As combustion conditions improve and hydrocarbon levels 
decrease, the larger and easier to combust compounds are oxidized to 
form smaller compounds that are, in turn, oxidized to form CO and 
water. As combustion continues, CO is then oxidized to form 
CO2 and water. Because CO is a difficult to destroy 
refractory compound (i.e., oxidation of CO to CO2 is the 
slowest and last step in the oxidation of hydrocarbons), it is a 
conservative surrogate for destruction of hydrocarbons, including 
organic HAP.
    Available control technologies for organic HAP emissions are of two 
types: Combustion and recovery. The combustion devices include thermal 
incinerators, catalytic incinerators, flares, and boilers/process 
heaters. Applicable recovery devices include condensers, adsorbers, and 
absorbers. The combustion devices are the more commonly applied control 
devices, since they are capable of high removal (i.e., destruction) 
efficiencies for almost any type of organic vapor HAP.\8\ As discussed 
below, the removal efficiencies of the recovery techniques generally 
depend on the physical and chemical characteristics of the organic HAP 
under consideration as well as the emission stream characteristics. 
Applicability of the control techniques depends on the individual 
emission stream under consideration. In this case, it would be emission 
streams from boilers and process heaters. The key emission stream 
characteristics and HAP characteristics that affect the applicability 
of each control technique are discussed below.
---------------------------------------------------------------------------

    \8\ Handbook Control Technologies for Hazardous Air Pollutants, 
EPA/625/6-91/014, June 1991, Center for Environmental Research 
Information, Office of Research and Development, U.S. EPA.
---------------------------------------------------------------------------

    Thermal incinerators use combustion to control a wide variety of 
continuous organic HAP emission streams. Compared to the other 
techniques, thermal incineration is broadly applicable; that is, it is 
much less dependent on HAP characteristics and emission stream 
characteristics. Destruction efficiencies up to 99 percent or higher 
are achievable with thermal incineration. Thermal incineration 
typically is applied to emission streams that are dilute mixtures of 
organic HAP and air.
    Catalytic incinerators are similar to thermal incinerators in 
design and operation except that they employ a catalyst to enhance the 
reaction rate. Since the catalyst allows the reaction to take place at 
lower temperatures, significant fuel savings may be possible with 
catalytic incineration. Catalytic incineration is not as broadly 
applicable as thermal incineration since performance of catalytic 
incinerators is more sensitive to pollutant characteristics and process 
conditions than is thermal incinerator performance. Materials in the 
emission stream can poison the catalyst and severely affect its 
performance. Destruction efficiencies of 95 percent of HAP can 
typically be achieved with catalytic incineration.
    Flares are commonly used for disposal of waste gases during process 
upsets and emergencies. They are basically safety devices that are also 
used to destroy waste emission streams. Flares can be used for 
controlling almost any organic HAP emission stream.

[[Page 52211]]

    Boilers or process heaters are used to control emission streams 
containing organic compounds. These are currently used as control 
devices for emission streams from several industries (e.g., refinery 
operations, polymers and resins operations, chemical reactor processes, 
and distillation operations, etc.). See 40 CFR part 63, subparts JJJ, 
OOO, and PPP. Typically, off-gases containing organic HAP emissions are 
controlled in boilers or process heaters and used as supplemental fuel 
if they have sufficient heating value. When used as emission control 
devices, boilers or process heaters can provide destruction 
efficiencies of greater than 98 percent.
    Carbon adsorption is a recovery (non-combustion) technique commonly 
employed as a pollution control and/or a solvent recovery technique. It 
is applied to dilute mixtures of HAP and air. Removal efficiencies of 
95 to 99 percent can be achieved using carbon adsorption. Outlet 
concentrations around 50 parts per million by volume (ppmv) can be 
routinely achieved with state-of-the-art systems; concentrations as low 
as 10 to 20 ppmv can be achieved with some compounds. Highly volatile 
materials (i.e., molecular weight less than about 45) do not adsorb 
readily on carbon; therefore, adsorption is not typically used for 
controlling emission streams containing such compounds. Carbon 
adsorption is also relatively sensitive to emission stream conditions, 
such as high humidity and temperatures.
    Absorption is widely used as a raw material and/or a product 
recovery technique in separation and purification of gaseous streams 
containing high concentrations of VOC. As an emission control 
technique, it is much more commonly employed for inorganic vapors than 
for organic vapors. Using absorption as the primary control technique 
for organic vapor HAP is subject to several limitations and problems. 
The suitability of absorption for controlling organic vapor emissions 
is determined by several factors; most of these factors will depend on 
the specific HAP in question. For example, the most important factor is 
the availability of a suitable solvent. The pollutant in question 
should be readily soluble in the solvent for effective absorption 
rates.
    Condensers are widely used as raw material and/or product recovery 
devices. They are frequently applied as preliminary air pollution 
control devices for removing VOC contaminants from emission streams 
prior to other control devices such as incinerators, adsorbers, or 
absorbers. Condensers are also used by themselves for controlling 
emission streams containing high VOC concentrations (usually >5,000 
ppmv). In these cases, removal efficiencies obtained by condensers can 
range from 50 to 90 percent although removal efficiencies at the higher 
end of the scale usually require HAP concentrations of around 10,000 
ppmv or greater. Therefore, it is not possible for condensation with 
water as the coolant to achieve the low outlet concentrations that 
would be required in HAP control applications.
    In summary, combustion is the more commonly applied technology for 
controlling organic HAP since it is capable of high removal 
efficiencies for organic HAP and its effectiveness does not depend on 
the makeup of the organic HAP stream or the organic HAP concentration. 
In fact, the devices regulated by the rule (boilers and process 
heaters) not only combust fuel for producing steam and/or process heat 
but serve a dual function in that they also effectively control organic 
HAP when good combustion conditions are present. Recovery (non-
combustion) devices are not applicable on all organic HAP and are not 
effective on low organic HAP concentration streams. Also, recovery 
devices' effectiveness is dependent on an emission stream with a high 
organic HAP content (>250 ppmv), compared to the organic HAP content of 
the emission streams from boilers which are around 1 ppmv for fossil 
fuels (coal and oil) and around 10 ppmv for biomass.\9\ Therefore, at 
the organic HAP levels generated and emitted from a boiler, the 
recovery (non-combustion) technologies would be ineffective. 
Furthermore, none of the best performing units employ any add-on 
alternative control device for controlling organic HAP. Many industrial 
boilers and process heaters employ post combustion controls for PM, 
acid gases, and/or Hg but these add-on controls do not affect emissions 
of CO or non-dioxin organic HAP.
---------------------------------------------------------------------------

    \9\ Based on emission factors reported on the EPA web page, AP 
42, Fifth Edition, Volume 1--Chapter 1: External Combustion Sources, 
located at https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf.
---------------------------------------------------------------------------

    For these reasons, we continue to conclude that the level of CO 
emissions, which indicates organic HAP reductions achieved through the 
use of combustion controls, is an appropriate surrogate for controlling 
organic HAP emissions from boilers and process heaters.

E. Proposed Response to the Amended Issue: CO 130 PPM Threshold 
Emission Limits

    The D.C. Circuit, on March 16, 2018, issued an opinion in the 
Boiler MACT reconsideration case, Sierra Club v. EPA, 884 F.3d 1185, 
which was a petition for review by environmental groups of the 2015 
reconsideration of the Boiler MACT rule. The case addressed two issues 
that were severed from the litigation challenging the 2013 Boiler MACT 
rule (U.S. Sugar v. EPA): (1) The 130-ppm threshold for CO standards, 
which, as described above, were established as a surrogate for non-
dioxin organic HAP and (2) the definitions of periods of startup and 
shutdown and the applicable work practices to be used during those 
periods. The court granted the petition as to the CO issue, finding 
that the EPA had not provided sufficient record support for the CO 
concentration threshold and remanded for further explanation, but 
denied the petition on the startup/shutdown issue and upheld the EPA's 
approach as consistent with the CAA.
    The court declined to revisit its opinion in U.S. Sugar, in which 
the court upheld the use of CO as a surrogate for organic HAP but 
remanded to the EPA to address whether there are means to reduce 
organic HAP other than by combustion. Against that backdrop, the court, 
in its decision in Sierra Club said the question before it was whether, 
assuming CO is an appropriate surrogate, the EPA's decision to 
establish a 130-ppm threshold as the lowest (i.e., most stringent) 
numeric CO limit was consistent with the requirements of the CAA. Based 
on a close examination of the record, the court held that the EPA had 
not sufficiently explained its rationale and questioned EPA's reliance 
on data regarding the relationship between formaldehyde and organic HAP 
that the EPA had previously characterized as unreliable.
    The court did note that if the EPA made and adequately supported a 
determination that no further reduction of HAP would occur once CO 
levels had been reduced to 130 ppm, the threshold would be appropriate 
and consistent with the CAA. The court noted three specific issues it 
believed the Agency did not adequately address: (1) The EPA gave no 
reason why organic HAP emissions could not be further reduced, once CO 
emissions reach 130 ppm, (2) the EPA relied on formaldehyde data to 
support its conclusion but elsewhere stated that the same data were not 
a reliable indicator of organic HAP emissions at very low levels, and 
(3) the EPA did not adequately explain if there is a non-zero CO level 
below which organic HAP levels cannot be further reduced, why 130 ppm 
is the appropriate level. Responses to these three issues are addressed 
below.

[[Page 52212]]

    In the January 31, 2013, final rule, we revised the CO emission 
limit for several subcategories, both new and existing, to reflect a CO 
level that, we stated, is consistent with MACT for organic HAP 
reduction. The revision was brought about by several commenters who 
recommended that the EPA evaluate a minimum CO standard (i.e., 100 ppm 
corrected to 7-percent oxygen \10\) to serve as a lower bound surrogate 
for organic HAP. The commenters also provided data and information to 
support such a standard and noted that the EPA has taken a similar 
approach in other emission standards under CAA section 112. See 40 CFR 
part 63, subpart EEE (NESHAP for Hazardous Waste Combustors).
---------------------------------------------------------------------------

    \10\ The CO emission standards in the 2013 final rule are 
corrected to 3-percent oxygen. The 130 ppm CO standards in the 2013 
final rule is equivalent to 100 ppm corrected to 7-percent oxygen.
---------------------------------------------------------------------------

    In the preamble to the 2013 final rule, we stated that we evaluated 
whether there is a minimum CO level for boilers and process heaters 
below which there is no further benefit in organic HAP reduction/
destruction. Specifically, we evaluated the relationship between CO and 
formaldehyde using the available data obtained during the rulemaking. 
Formaldehyde was selected as the basis of the organic HAP comparison 
because it is the most prevalent organic HAP in the emission database 
and many paired tests existed for boilers and process heaters for CO 
and formaldehyde and because formaldehyde was the only organic HAP for 
which we had such data. The paired data show decreasing formaldehyde 
emissions with decreasing CO emissions down to CO levels around 300 ppm 
(with formaldehyde emissions down to less than 1 ppm), supporting the 
selection of CO as a surrogate for organic HAP emissions. A slight 
increase in formaldehyde emissions, to between 1 and 2 ppm, was 
observed at CO levels below around 200 ppm, suggesting a breakdown in 
the CO-formaldehyde relationship at low CO concentrations. At levels 
lower than 150 ppm, the mean levels of formaldehyde appeared to 
increase, as does the overall maximum value of and variability in 
formaldehyde emissions. However, at that time, we were not aware of any 
reason why formaldehyde concentrations would increase as CO 
concentrations continue to decrease, indicating improved combustion 
conditions. Our thinking at the time was that imprecise formaldehyde 
measurements at low concentrations (i.e., 1-2 ppm) may have accounted 
for this slight increase in formaldehyde emissions observed at CO 
levels below 130 ppm.
    In the preamble of the 2013 final rule, we stated, ``Based on this, 
we do not believe that such measurements are sufficiently reliable to 
use as a basis for establishing an emissions limit.'' See 78 FR 7145. 
In that statement, we were referring to the formaldehyde measurements 
and, thus, to the decision to set a CO standard instead of a 
formaldehyde standard. Based on that analysis, we promulgated a minimum 
MACT floor level for CO of 130 ppm corrected to 3-percent oxygen (which 
is equivalent to 100 ppm corrected to 7-percent oxygen). We noted this 
was the same approach used to establish the CO emission limit of 100 
ppm corrected to 7-percent oxygen for the Burning of Hazardous Waste in 
Boilers and Industrial Furnaces final rule (56 FR 7134, February 21, 
1991). In that rulemaking, the EPA chose the 100-ppm (corrected to 7-
percent oxygen) limit because the research indicated that while CO was 
a good surrogate for the destruction of organic HAP, the validity of 
that surrogacy was questionable at CO levels of approximately 400 ppm 
and below. Based on the EPA's authority under the Resource Conservation 
and Recovery Act to establish standards that are protective of human 
health and the environment, the Agency established the 100-ppm 
standard. The EPA later established the 100-ppm corrected to 7-percent 
oxygen standard as the MACT standard for hazardous waste combustors 
(see 70 FR 59462) and explained why that standard was an appropriate 
floor (see 69 FR at 21282).
    The trend that our CO--formaldehyde data present has also been 
observed in a study \11\ done on polycyclic aromatic hydrocarbons (PAH) 
emissions from coal combustion. PAH constitute a group of organic HAP. 
The study presents a graph of PAH vs. excess oxygen \12\ which shows 
that at the lowest percentage of excess oxygen (5 percent), the highest 
PAH amount (0.25 ppm) is measured and shows minimum PAH emissions (0.02 
ppm) at 20-percent excess oxygen. The graph further shows that as the 
excess oxygen level increases above 20 percent, higher PAH emissions 
(about 0.06 ppm at 40 percent excess air) are observed. The study does 
not present corresponding CO values. However, the study does provide 
information showing that CO emissions continue to decrease with 
increasing excess oxygen levels above 20 percent, as indicated by the 
increased combustion efficiencies reported in the study for excess 
oxygen over the range of 5 to 40 percent. Combustion efficiency (CE) is 
a measure of the completeness of oxidation of all fuel (organic) 
compounds and is determine by the CE Formula: CE = [CO2/
(CO2 + CO)] x 100.\13\ Thus, CE increases with decreasing CO 
levels.
---------------------------------------------------------------------------

    \11\ Organic Atmospheric Pollutants: Polycyclic Hydrocarbons 
from Coal Atmospheric Fluidised Bed Combustion (AFBC), A.M Mastral, 
M.S. Callen, R. Murillo, and T. Garcia, Instituto de Carboquimica, 
1999.
    \12\ Excess oxygen, or excess air, is commonly used to define 
combustion. The excess oxygen is the amount of oxygen in the 
incoming air not used during combustion. Inadequate excess oxygen 
results in unburned combustibles (fuel and CO), while too much 
excess oxygen results in increased flue gas flow and decreased 
temperature and residence time for combustion.
    \13\ CE formula and calculator, https://ncalculators.com/environmental/combustion-efficiency-calculator.htm.
---------------------------------------------------------------------------

    The PAH study does provide a possible explanation for this 
phenomenon. In order to assess the PAH emissions as a function of 
combustion variables, the first aim of the study was to reach maximum 
CE. The study stated that ``it can be assumed that the emissions due to 
bad combustion have practically been eliminated, and so the data 
obtained will be due to the combustion process.'' The study states that 
at the lowest percentages of excess oxygen, the interaction between 
oxygen and radicals should be less favored and, as a result, the PAH 
amount would be higher. At the highest percentages of excess oxygen 
possible, interaction with PAH seemed to be minimized due to the higher 
gas velocities shortening the contact resulting in increasing PAH 
emissions.
    Furthermore, the EPA's Office of Research and Development (ORD), in 
support of the NESHAP from Coal- and Oil-Fired Electric Utility Steam 
Generating Units (also known as the Mercury and Air Toxics Standards or 
MATS), conducted a series of tests in the Agency's Multipollutant 
Control Research Facility (MPCRF). As part of these tests, potential 
surrogate relationships were examined for various non-D/F organic HAP. 
The objective of the testing program was to collect selected HAP 
emission data while firing coals under varied test conditions and 
evaluate relationships between those concentrations and other process 
concentrations and/or conditions. One of the principal objectives was 
to measure concentrations of non-D/F organic HAP and compare to the 
emission of candidate surrogates (e.g., CO, total hydrocarbons, etc.) 
\14\ Several organic HAP, discussed below and

[[Page 52213]]

presented as figures in the study's final report, were quantified from 
multiple tests with CO concentrations and show a similar trend.
---------------------------------------------------------------------------

    \14\ Surrogacy Testing in the MPCRF, Prepared for U.S. EPA, 
Prepared by ARCADIS, March 30, 2011. See Docket ID Item No. EPA-HQ-
OAR-2002-0058-3942.
---------------------------------------------------------------------------

    Figure 4-16 of the MPCRF study shows the concentration of phenol, 
an organic HAP, plotted against concentration of CO. CO concentrations 
ranged from 40 to 140 ppm, at 7-percent oxygen, with phenol 
concentrations ranging from 0.6 parts per billion (ppb) at 40 ppm CO to 
1 ppb at 140-ppm CO with the lowest phenol concentration (0.5 ppb) 
measured at 95-ppm CO (120-ppm CO at 3-percent oxygen).
    The MPCRF study also examined formaldehyde emissions against CO 
concentrations. The five data points (Figure 4-17 of the study) are all 
for CO concentrations below 70 ppm with the lowest formaldehyde 
emissions (10 ppb) measured at 70-ppm CO and with higher formaldehyde 
emissions (57 ppb) measured at a lower CO level of 40-ppm CO.
    In addition, the MPCRF study shows similar results for chloroform 
(another organic HAP). The five data points (Figure 4-24 of the study) 
show chloroform emissions of 0.038 ppb at 170-ppm CO at 3-percent 
oxygen, 0.025 ppb chloroform at 130-ppm CO at 3-percent oxygen, and 
0.054 ppb chloroform at 40-ppm CO at 3-percent oxygen.
    The MPCRF does not present any explanation on why these trends were 
observed. One of the goals of the MPCRF testing was to determine or 
demonstrate a relationship between concentrations of organic compounds 
and combustion conditions. However, due to low emission levels, non-
detects, and other complexities, the key conclusion drawn was that the 
testing did not disprove an expected relationship between organic 
concentrations and combustion conditions.
    There are myriad factors that affect CE and, as a function of CE, 
CO emissions. As combustion conditions improve and hydrocarbon levels 
decrease, the larger and easier to combust compounds are oxidized to 
form smaller compounds that are, in turn, oxidized to form CO and 
water. As combustion continues, CO is then oxidized to form 
CO2 and water. Because CO is a difficult to destroy 
refractory compound (i.e., oxidation of CO to CO2 is the 
slowest and last step in the oxidation of hydrocarbons), it has been 
considered a conservative surrogate for destruction of hydrocarbons, 
including organic HAP.
    Neither the PAH study nor the MPCRF study provide an explanation 
for the phenomenon observed in these studies. In trying to explain why 
this phenomenon occurs, we know that combustion is the chemical 
reaction of oxygen with combustible compounds (e.g., organics) and that 
time, temperature, and turbulence impact the speed and completeness of 
the combustion reaction. For complete combustion, the oxygen must come 
into intimate contact with the combustible molecule at sufficient 
temperature, and for a sufficient length of time, in order to complete 
the reaction. Two factors that affect reaction rates are the 
concentration of the reactants (oxygen and organic HAP) and the 
temperature of the reactants. Every combustible substance has a minimum 
ignition temperature, which must be attained or exceeded, in the 
presence of oxygen, if combustion is to ensue under the given 
conditions. Lower concentrations will produce a decrease in the rate of 
reaction and a decrease in the temperature will decrease rate of 
reaction. As more ambient temperature combustion air (oxygen) is added, 
the concentration and temperature of the reactant (organic HAP) is 
reduced. Thus, a potential explanation is that with the increased 
combustion air (oxygen), the resulting increased turbulence, while 
providing increased mixing, can result in more organic molecules being 
forced near the furnace walls, which are cold compared to the 
combustion zone. This can essentially slow down or quench the 
combustion reactions by cooling the molecules of the organic compounds 
to below their minimum ignition temperature. Thus, those organic HAP 
molecules would not be combusted and would be emitted unchanged. Any 
action having the effect of decreasing the reaction rate of the organic 
HAP will consequently result in less organic HAP being combusted and, 
thus, higher organic HAP emissions being observed and appear to be an 
increase, at higher excess oxygen (and lower CO emissions) levels.
    The range of the formaldehyde measurements for the reported paired 
formaldehyde-CO emissions data for the 97 emission units is 0.00009 ppm 
(0.09 ppb) to 2.0 ppm. The mathematical average of the corresponding CO 
emissions from the best performing 12 percent of units, identified as 
those units with the lowest formaldehyde emissions, is 137 ppm.
    At the time of the 2013 rulemaking, we observed that reducing CO 
emissions also resulted in a reduction of organic HAP emissions until a 
leveling off in organic HAP reduction is reached after which further 
reduction of CO levels appeared to result in higher levels of organic 
HAP emitted. Our determination that setting a CO standard below a CO 
level of 130 ppm would result in no additional organic HAP reduction is 
supported by both the independent PAH emission study and the MPCRF 
study which both show similar trends. That is, organic HAP levels 
decreased with decreasing CO levels until a leveling off and trending 
upward with further decreasing CO levels. Also, based on the level of 
the organic HAP emissions measured in the two studies, we do not 
consider the formaldehyde data used in our establishment of the 130 ppm 
CO standard to have been imprecise and, thus, unreliable. The 
formaldehyde data measured at CO levels below 130 ppm reflect the 
variability (scatter) of organic HAP emissions when each data point is 
from a different unit. Whereas, the organic HAP emission results 
presented in the two studies, which were measured at similar low 
concentrations, are from tests conducted on a single unit at varying CO 
levels.
    The seven subcategories with the 130 ppm CO level in the 2013 final 
rule are: (1) Pulverized Coal Boilers; (2) Coal Stokers; (3) Coal 
Fluidized Bed; (4) Heavy Liquid Fuel; (5) Light Liquid Fuel; (6) Non-
Continental Liquid; and (7) Process Gas. Based on our review of the 
data in 2013, we established that a CO emission level of 130 ppm 
represented MACT for controlling organic HAP emissions for units in the 
six subcategories. Based on additional information obtained during and 
after the rulemaking, as discussed above, we reaffirm our conclusion 
that a 130-ppm CO concentration threshold represents MACT for organic 
HAP for the six subcategories.

IV. Results and Proposed Decisions

A. What are the resulting changes to emission limits?

    Based on all of the revisions made to address the remand related to 
ranking and assessing co-fired units in the MACT floor calculations, 
the changes made for UPL calculations for small datasets, and the 
decisions to propose certain limits as beyond-the-floor limits, there 
are 34 different emission limits that we are proposing to change. The 
detailed list of revisions to unit rankings and revised MACT floor 
calculations are presented in the docketed memorandum, Revised MACT 
Floor Analysis (2019) for the Industrial, Commercial, and Institutional 
Boilers and Process Heaters National Emission Standards for Hazardous 
Air Pollutants--Major Source. Of these 34 emission limits, 28 of the 
limits are more stringent than the corresponding limits in the 2013 
final rule. Six of the

[[Page 52214]]

limits are modestly less stringent, with no more than a 25-percent 
increase. The proposed and corresponding current limits are shown in 
Table 6.

                      Table 6--Summary of Changes to Emission Limits in the Proposed Action
----------------------------------------------------------------------------------------------------------------
                                                                        Current emission      Proposed emission
                                                                       limit (lb/MMBtu of    limit (lb/MMBtu of
              Subcategory                         Pollutant           heat input or ppm at  heat input or ppm at
                                                                      3-percent oxygen for  3-percent oxygen for
                                                                               CO)                   CO)
----------------------------------------------------------------------------------------------------------------
New-Solid.............................  HCl.........................               2.2E-02               3.0E-04
New-Dry Biomass Stoker................  TSM8........................               4.0E-03               5.0E-03
New-Biomass Fluidized Bed.............  CO..........................                   230                   130
New-Biomass Fluidized Bed.............  PM (TSM)....................     9.8E-03 (8.3E-05)     4.1E-03 (8.4E-06)
New-Biomass Suspension Burner.........  CO..........................                 2,400                   220
New-Biomass Suspension Burner.........  TSM.........................               6.5E-03               8.0E-03
New-Biomass Hybrid Suspension Grate...  CO..........................                 1,100                   180
New-Biomass Dutch Oven/Pile Burner....  PM..........................               3.2E-03               2.5E-03
New-Biomass Fuel Cell.................  PM..........................               2.0E-02               1.1E-02
New-Wet Biomass Stoker................  CO..........................                   620                   590
New-Wet Biomass Stoker................  PM..........................                  0.03                 0.013
New-Liquid............................  HCl.........................               4.4E-04               7.0E-05
New-Heavy Liquid......................  PM (TSM)....................     1.3E-02 (7.5E-05)     1.9E-03 (6.4E-06)
New-Process Gas.......................  PM..........................               6.7E-03               7.3E-03
Existing-Solid........................  HCl.........................               2.2E-02               2.0E-02
Existing-Solid........................  Hg..........................               5.7E-06               5.4E-06
Existing-Coal.........................  PM..........................               4.0E-02               3.9E-02
Existing-Coal Stoker..................  CO..........................                   160                   150
Existing-Dry Biomass Stoker...........  TSM.........................               4.0E-03               5.0E-03
Existing-Wet Biomass Stoker...........  CO..........................                 1,500                 1,100
Existing-Wet Biomass Stoker...........  PM (TSM)....................     3.7E-02 (2.4E-04)     3.4E-02 (2.0E-04)
Existing-Biomass Fluidized Bed........  CO..........................                   470                   210
Existing-Biomass Fluidized Bed........  PM (TSM)....................     1.1E-01 (1.2E-03)     2.1E-02 (6.4E-05)
Existing-Biomass Suspension Burners...  PM (TSM)....................     5.1E-02 (6.5E-03)     4.1E-02 (8.0E-03)
Existing-Biomass Dutch Oven/Pile        PM..........................               2.8E-01               1.8E-01
 Burner.
Existing-Liquid.......................  Hg..........................               2.0E-06               7.3E-07
Existing-Heavy Liquid.................  PM..........................               6.2E-02               5.9E-02
Existing-Non-Continental Liquid.......  PM..........................               2.7E-01               2.2E-01
Existing-Process Gas..................  PM..........................               6.7E-03               7.3E-03
----------------------------------------------------------------------------------------------------------------

    The EPA requests comment on the revisions to the emission limits in 
light of the changes the EPA has proposed in response to the remand. 
Broader comments with respect to the UPL calculation methodology will 
not be considered within the scope of this rulemaking. The EPA will 
only consider data that is already available in the rulemaking record. 
The EPA also requests comments on its determination of beyond-the-floor 
emission limits for certain subcategories. The emission reduction 
impacts associated with these changes to the MACT floor emission limits 
are discussed in the docketed memorandum Revised (2019) Methodology for 
Estimating Impacts for Industrial, Commercial, Institutional Boilers 
and Process Heaters National Emission Standards for Hazardous Air 
Pollutants.

B. What compliance dates are we proposing?

    The EPA is proposing that facilities have up to 3 years after the 
effective date of the final rule to comply with the new emissions 
limits in the final rule. Before this date, facilities must continue to 
comply with the rule as it was finalized in 2015. This allowance is 
being made considering that some facilities may require additional add-
on controls or monitoring equipment to be designed, purchased, and 
installed in order to meet the more stringent emission limits, or to 
modify the method of compliance based on the changes in emission 
limits. In addition, units will require lead time to prepare and 
execute their testing plans to demonstrate compliance with the updated 
emission limits and to update reports to incorporate the revised 
emission limits. The EPA requests comment on this time frame.

C. What other actions are we proposing?

    We are proposing several technical corrections. These amendments 
are being proposed to correct inadvertent errors that were promulgated 
in the final rule. We are soliciting comment only on whether the 
proposed changes provide the intended accuracy, clarity, and 
consistency. These proposed changes are described in Table 7 of this 
preamble. We request comment on all these proposed changes.

[[Page 52215]]



Table 7--Miscellaneous Proposed Technical Corrections to 40 CFR Part 63,
                              Subpart DDDDD
------------------------------------------------------------------------
   Section of subpart DDDDD        Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.7500(a)............  Revise this paragraph to remove the comma
                                after ``paragraphs (b).''
40 CFR 63.7521(c)(1)(ii)       Revise this paragraph to remove the
                                requirement to collect samples during
                                the test period at 1-hour intervals.
40 CFR 63.7530(b)(4)(iii)      Revise this paragraph to remove the
                                sentence regarding establishing the pH
                                operating limit because establishing the
                                pH operating limit is not required for a
                                PM wet scrubber.
40 CFR 63.7540(a)(9)           Revise this paragraph to clarify that
                                ``certify'' is intended to apply only to
                                PM CEMS, not PM continuous parameter
                                monitoring systems (CPMS) because PM
                                CPMS do not have a performance
                                specification.
40 CFR 63.7575...............  Revise the definition of ``Other gas 1
                                fuel'' to clarify that it is the maximum
                                Hg concentration of 40 micrograms/cubic
                                meter of gas.
                               Add definition of ``12-month rolling
                                average'' to clarify that the previous
                                12 months must be consecutive but not
                                necessarily continuous.
                               Revise paragraph (4) of definition
                                ``Steam output'' to correct ``heaters''
                                to ``headers.''
Table 1 to subpart DDDDD       Revise the output limit in item 8.a to
                                correct for a rounding error, the value
                                is now 4.3E-01 lb per MMBtu instead of
                                4.2E-01 lb per MMBtu.
Table 7 to subpart DDDDD       Revise footnote ``b'' to clarify that
                                when multiple performance tests are
                                conducted, the maximum operating load is
                                the lower of the maximum values
                                established during the performance
                                tests.
Table 8 to subpart DDDDD       Revise item 8.d to clarify that the
                                correct equations to use are Equations
                                7, 8, and/or 9 in 40 CFR 63.7530.
------------------------------------------------------------------------

V. Summary of Cost, Environmental, and Economic Impacts

A. What are the affected sources?

    As mentioned previously, this rule affects a wide range of 
facilities in the ICI sector that are located at major sources of HAP 
and have a boiler or process heater as defined in the final rule. The 
2013 Emission Database for Boilers and Process Heaters estimated there 
were approximately 14,000 existing boilers and process heaters 
currently operating at 1,702 different facilities that are major 
sources of HAP and subject to the Boiler MACT. The vast majority of 
these combustion units (nearly 12,000 units) were gas-fired and in the 
Gas 1 subcategory, which are subject to the rule but are not subject to 
numeric emission limits. Another 472 units were small or limited use 
and were also not subject to numeric emission limits. By contrast, the 
EPA has reviewed compliance data submitted to CEDRI and WebFIRE and the 
trade association Council of Industrial Boilers, which had provided 
input on units that had shutdown or switched to natural gas fuel as 
part of its compliance strategy. The EPA then compiled an updated 
estimate of units that are subject to emission limits. These data show 
533 existing boilers and process heaters, of which 443 remain 
operational and belong in one of the subcategories that are subject to 
numeric emission limits. This count excludes any boilers that are no 
longer operational, boilers that have refueled and switched to the 
natural gas subcategory and are, therefore, no longer impacted by 
changes to emission limits, or boilers that are classified as small or 
limited use.
    For new sources, the EPA had projected new sources anticipated to 
be built by 2015 from a baseline year of 2008.\15\ While the 
projections had anticipated correctly that the only new units subject 
to emission limits would be new large biomass units, the actual number 
of new units is significantly lower than projected in the January 2013 
final rule. The CEDRI and WebFIRE compliance data provided updates on 
eight new biomass units that are subject to emission limits and 
reporting compliance data. Since new units have had to comply since 
April 2013, these eight units reflect a new unit rate of 1.3 new units 
per year during the 6-year period of April 2013 through April 2019. 
Using these new source data, the EPA estimates that, four more biomass 
boilers or process heaters are expected to be constructed over the next 
3 years. As such, 12 new boilers and process heaters are estimated to 
be affected by the proposed amendments.
---------------------------------------------------------------------------

    \15\ See docketed memorandum: Revised New Unit Analysis 
Industrial, Commercial, and Institutional Boilers and Process 
Heaters National Emission Standards for Hazardous Air Pollutants--
Major Source. November 2011. Docket ID Item No. EPA-HQ-OAR-2002-
0058-3388.
---------------------------------------------------------------------------

    Table 8 presents a summary table comparing the number of existing 
and new affected sources, by subcategory. The counts exclude small or 
limited use units.

        Table 8--Summary of Changes to Number of Affected Sources
------------------------------------------------------------------------
                                      Estimate of         Estimate of
           Subcategory              sources in 2013     sources in 2019
                                      final rule           proposal
------------------------------------------------------------------------
Existing-Biomass................  481...............  285.
Existing-Coal...................  606...............  124.
Existing-Heavy Liquid...........  291...............  6.
Existing-Light Liquid...........  260...............  24.
Existing-Non-Continental Liquid.  19................  5.
Existing-Process Gas............  78................  0.
New-Biomass.....................  78 (projected       8 (actual) + 4
                                   online by 2015).    (projected).
New-Coal........................  0.................  0.
New-Heavy Liquid................  0.................  0.
New-Light Liquid................  0.................  0.
New-Non-Continental Liquid......  0.................  0.
New-Process Gas.................  0.................  0.
------------------------------------------------------------------------


[[Page 52216]]

B. What are the air quality impacts?

    Table 9 of this preamble illustrates, for each basic fuel 
subcategory, the incremental emissions reductions that would be 
achieved by the proposed amendments. The reductions are all additional 
to the reductions accounted for in the January 2013 final rule for both 
new and existing sources. Nationwide emissions of selected HAP (i.e., 
HCl, hydrogen fluoride, Hg, metals) would be reduced by an additional 
37.35 tpy as compared to the estimates in the January 2013 final rule. 
This additional decrease is due mainly to changes to certain emission 
limits that are anticipated to achieve additional reductions. The 
proposed amendments are expected to result in an additional 34 tpy of 
reductions in HCl emissions. The proposed amendments are also expected 
to have a modest effect on Hg, with an estimated additional reduction 
of 3.96 lbs per year. Emissions of filterable PM would decrease by 333 
tpy, of which 251 tpy is PM2.5, due to the proposed 
amendments. Emissions of non-Hg metals (i.e., antimony, arsenic, 
beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and 
selenium) would decrease by 2.3 tpy. In addition, the proposed 
amendments are estimated to result in an additional 393 tpy of 
reductions in SO2 emissions. A discussion of the methodology 
used to estimate emissions, emissions reductions, and incremental 
emission reductions is presented in the memorandum, Revised (2019) 
Methodology for Estimating Impacts for Industrial, Commercial, 
Institutional Boilers and Process Heaters National Emission Standards 
for Hazardous Air Pollutants, which is available in the docket for this 
action.

                      Table 9--Summary of Total Emissions Reductions for the Proposed Rule
                                                    [Tons/Yr]
----------------------------------------------------------------------------------------------------------------
                                                                                   Non-Hg metals
            Source                 Subcategory          HCl             PM              \1\             Hg
----------------------------------------------------------------------------------------------------------------
Exiting Units.................  Coal............             9.8               0               0        1.88E-03
                                Biomass.........            14.5             333             2.3        1.79E-04
New Units.....................  Biomass.........             9.8               0               0               0
----------------------------------------------------------------------------------------------------------------
\1\ Antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.

C. What are the cost impacts?

    We estimated the total capital costs of the proposed amendments to 
be about $83 million and the total annualized costs to be about $22 
million in 2016 dollars. The total capital and annual costs include 
costs for control devices, testing, and monitoring associated with the 
changes to the emission limits. These costs are incremental to the 
costs presented in the January 2013 final rule in the sense that they 
show where units with compliance data must install add-on controls or 
modify compliance strategies in order to meet the more stringent limits 
in this proposal. Table 10 of this preamble shows the total capital and 
annual cost impacts of the proposed rule for each subcategory. The cost 
methodology and results are documented in the memorandum, Revised 
(2019) Methodology for Estimating Impacts for Industrial, Commercial, 
Institutional Boilers and Process Heaters National Emission Standards 
for Hazardous Air Pollutants, which is available in the docket for this 
action.

     Table 10--Summary of Total Capital and Annual Costs for New and Existing Sources for the Proposed Rule
                                                     [2016$]
----------------------------------------------------------------------------------------------------------------
                                                                                    Testing and
                                                    Estimated/                      monitoring      Annualized
            Source                 Subcategory       projected     Capital costs    annualized    cost (10\6\ $/
                                                     number of       (10\6\ $)    costs (10\6\ $/       yr)
                                                  affected units                        yr)
----------------------------------------------------------------------------------------------------------------
Existing Units                  Coal............               2           0.803           0.006           0.327
                                Biomass.........              26            81.1           0.267            20.5
New Units.....................  Solid units (all               5           0.952           0.017           0.653
                                 biomass)
----------------------------------------------------------------------------------------------------------------

    In addition, another way to present compliance costs is the PV. A 
PV is an estimate of costs that is a discounted stream of the 
annualized costs for the proposal calculated for the present day. The 
PV in 2016 of the costs is $103.7 million at a discount rate of 7 
percent and $128.1 million at 3 percent. Calculated as an EAV, which is 
consistent with the PV of costs in 2016, the costs are $17.4 million at 
a discount rate of 7 percent and $18.3 million at a discount rate of 3 
percent. These estimates are also in 2016 dollars. More information on 
the PV and EAV estimates can be found in the RIA for this proposal that 
is in the docket for this action.

D. What are the secondary impacts?

    The EPA estimated the additional water usage that would result from 
installing wet scrubbers to meet the proposed amended emission limits 
for HCl would be 0.64 million gallons per year for new and existing 
sources compared to the current baseline. In addition to the increased 
water usage, an additional 0.27 million gallons per year of wastewater 
would be produced for new and existing sources. The annual costs of 
treating the additional wastewater are approximately $1,830. These 
additional costs are accounted for in the control cost estimates.

[[Page 52217]]

    The EPA estimated the additional solid waste that would result due 
to the proposed amendments to be 1,550 tpy for new and existing 
sources. Solid waste is generated from flyash and dust captured in 
fabric filters and electrostatic precipitators (ESP) installed for PM 
and Hg controls as well as from spent materials from wet scrubbers and 
sorbent injection systems installed for additional HCl controls. The 
costs of handling the additional solid waste generated are $74,100. 
These costs are also accounted for in the control costs estimates.
    The EPA estimated the proposed amendments would result in an 
increase of about 29.5 million kilowatts per year in national energy 
usage from the electricity required to operate control devices, such as 
wet scrubbers, ESPs, and fabric filters which are expected to be 
installed to meet the proposed rule. This energy requirement is 
estimated to result in an increase of approximately 17,740 tpy 
CO2 based on emissions related to additional energy 
consumption.
    A discussion of the methodology used to estimate impacts is 
presented in the Revised (2019) Methodology for Estimating Impacts for 
Industrial, Commercial, Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants, which is 
available in the docket for this action.

E. What are the economic impacts?

    The EPA conducted an economic impact analysis for this proposal, as 
detailed in the Regulatory Impact Analysis for the Proposed ICI Boilers 
NESHAP Reconsideration, which is available in the docket for this 
action. The economic impacts of the proposal are calculated as the 
percentage of total annualized costs incurred by affected parent owners 
to their annual revenues. This ratio of total annualized costs to 
annual revenues provides a measure of the direct economic impact to 
parent owners of affected facilities while presuming no passthrough of 
costs to consumers of output produced by these facilities. We estimate 
that none of the 26 parent owners affected by this proposal will incur 
total annualized costs of 0.70 percent or greater of their revenues. 
Thus, these economic impacts are quite low for the affected companies 
and the multiple affected industries, and consumers of affected output 
should experience minimal price changes.

F. What are the benefits?

    The EPA reports the estimated impact on health benefits from 
changes in PM2.5 and SO2 emissions. The estimated 
health co-benefits are the monetized value of the human health benefits 
among populations exposed to changes in PM2.5. These 
benefits are co-benefits in this analysis since these pollutants are 
not targeted for control by this proposal. This rule is expected to 
alter the emissions of PM2.5 (and SO2). Due to 
the small change in emissions expected, we used the ``benefit per ton'' 
(BPT) approach to estimate the benefits of this rulemaking. The EPA has 
applied this approach in several previous RIAs \16\ in which the 
economic value of human health impacts are derived at the national 
level based on previously established source-receptor relationships 
from photochemical air quality modeling.\17\ These BPT estimates 
provide the total monetized human health benefits (the sum of premature 
mortality and premature morbidity) of reducing 1 ton of 
PM2.5 (or PM2.5 precursor such as nitrogen oxide 
or SO2) from a specified source. Specifically, in this 
analysis, we multiplied the estimates from the ``Industrial Point 
Sources'' sector by the corresponding emission reductions. This assumes 
that the emissions reductions from this proposed rule for industrial 
boilers scale linearly with the BPT Industrial Point Sources sector. 
The method used to derive these estimates is described in the Technical 
Support Document on estimating the BPT of reducing PM2.5 and 
its precursors from 17 sectors.\18\ One limitation of using the BPT 
approach is an inability to provide estimates of the health benefits 
associated with exposure to HAP (HCl, for example), CO, nitrogen 
dioxide, or ozone. The photochemical modeled emissions of the 
industrial point source sector-attributable PM2.5 
concentrations used to derive the BPT values may not match the change 
in air quality resulting from the emissions controls. The 
PM2.5 emission reductions resulting from this rule are 
approximately 0.4 percent of the PM2.5 annual emissions and 
0.04 percent of the SO2 emissions attributable to the BPT 
Industrial Point Sources. For this reason, the health co-benefits 
reported in Table 11 may be larger, or smaller, than those realized 
through this rule. We are taking comment on the modeling assumptions 
behind the benefits analysis results mentioned above as well as the 
utility of performing full-form (i.e., full-scale) photochemical 
modeling for the final rule.
---------------------------------------------------------------------------

    \16\ U.S. EPA. Regulatory Impact Analysis for the Federal 
Implementation Plans to Reduce Interstate Transport of Fine 
Particulate Matter and Ozone in 27 States; Correction of SIP 
Approvals for 22 States. June 2011; Regulatory Impact Analysis for 
the Final Mercury and Air Toxics Standards, December 2011; and 
Regulatory Impact Analysis for the Particulate Matter National 
Ambient Air Quality Standards; December 2012.
    \17\ Fann N, Fulcher CM, Hubbell BJ. The influence of location, 
source, and emission type in estimates of the human health benefits 
of reducing a ton of air pollution. Air Qual Atmos Health. 
2009;2(3):169-176. doi:10.1007/s11869-009-0044-0.
    \18\ U.S. EPA, Technical Support Document. Estimating the 
Benefit per Ton of Reducing PM2.5 Precursors from 17 
Sectors. February 2018.
---------------------------------------------------------------------------

    Table 11 summarizes the monetized PM-related health benefits per 
ton or reducing precursor pollutant emissions, using discount rates of 
3 percent and 7 percent.

       Table 11--Estimated PM2.5-Related Benefits per Ton of Proposed ICI Boilers and Process Heaters MACT
                                                 Reconsideration
----------------------------------------------------------------------------------------------------------------
                        Epidemiologic study used to quantify PM-related premature deaths
-----------------------------------------------------------------------------------------------------------------
                                              Krewski et al. (2009)                 Lepeule et al. (2012)
                                     ---------------------------------------------------------------------------
              Pollutant                BPT  (3-percent    BPT  (7-percent    BPT  (3-percent    BPT  (7-percent
                                        discount rate)     discount rate)     discount rate)     discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5...............................           $330,000           $300,000           $790,000           $690,000
SO2.................................             52,000             47,000            120,000            100,000
----------------------------------------------------------------------------------------------------------------


[[Page 52218]]

    Table 12 summarizes the range of estimated benefits by pollutant 
for the two BPT estimates at discount rates of 3 percent and 7 percent.

       Table 12--Estimated PM2.5-Related Health Benefits of Proposed ICI Boilers and Process Heaters MACT
                                                 Reconsideration
----------------------------------------------------------------------------------------------------------------
                    Epidemiologic study used to quantify PM and SO2-related premature deaths
-----------------------------------------------------------------------------------------------------------------
                                              Krewski et al. (2009)                 Lepeule et al. (2012)
                                     ---------------------------------------------------------------------------
                                           Benefits           Benefits           Benefits           Benefits
              Pollutant                  (millions of       (millions of       (millions of       (millions of
                                      2016$,  3-percent  2016$,  7-percent  2016$,  3-percent  2016$,  7-percent
                                        discount rate)     discount rate)     discount rate)     discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5...............................                $84                $76               $200               $170
SO2.................................                 21                 19                 49                 40
                                     ---------------------------------------------------------------------------
    Total...........................                110                 95                250                210
----------------------------------------------------------------------------------------------------------------

    All BPT estimates have inherent limitations. Specifically, all 
national-average BPT estimates reflect the geographic distribution of 
the modeled emissions, which may not exactly match the emission 
reductions in this rulemaking, and they may not reflect local 
variability in population density, meteorology, exposure, baseline 
health incidence rates, or other local factors for any specific 
location. The photochemical modeled emissions of the industrial point 
source sector-attributable PM2.5 concentrations used to 
derive the BPT values may not match well the change in air quality 
resulting from the emissions controls. For this reason, the health 
benefits reported here may be larger, or smaller, than those realized 
by this rule.
    There are also climate disbenefits from the increase in 
CO2 emissions that result from the increase in national 
energy use from control device operation. The disbenefits are $0.09 
million at a 3-percent discount rate and $0.01 million at a 7-percent 
discount rate. These calculations reflect the domestic social cost of 
carbon for CO2 for 2025, the year for which benefits are 
estimated that is an approximation for 2023, the year of full rule 
compliance. These disbenefits are included in the estimates of benefits 
and net benefits for this proposal.
    The benefit analysis for this proposal is detailed in the 
Regulatory Impact Analysis for the Proposed ICI Boilers and Process 
Heaters NESHAP Reconsideration, which is available in the docket for 
this action.

VI. Request for Comments

    The EPA is seeking comments on the issues raised in this proposal. 
It will not respond to comments addressing any other issues. 
Specifically, the EPA is seeking comments on the revised MACT floor 
emission limit calculations, including any comments or corrections to 
the underlying data used to compute those emission limits, the 
selection of beyond-the-floor limits for certain subcategories. The EPA 
is also seeking input on the inventory of units used to quantify the 
impacts of these proposed amendments, which relied on real compliance 
data submitted to CEDRI and WebFIRE through April 2019, and the 
methodology used to quantify the impacts analysis discussed in section 
V of this preamble. The EPA is also seeking comments on the accuracy of 
the control technology assessment and/or whether there are other 
compliance options available to meet the proposed revised emissions 
limits. Finally, we request comment on the Agency's approach for using 
a Benefit per-Ton value to quantify benefits as well as the utility of 
performing full-form modeling for the final rule.
    The current version of this regulation contains language which 
details how facilities that seek to monitor CO2 in lieu of 
oxygen as part of their CEMS used to demonstrate compliance with the CO 
emission limits in this subpart must have this approach approved as an 
alternative method before doing so. The EPA is seeking comment on 
replacing the requirement to have approval of an alternative test 
method with a required methodology to be followed when monitoring 
CO2 in lieu of oxygen as the diluent for CO which would 
account for any changes in CO2 emission levels caused by a 
control device, etc. Additionally, the EPA believes it is appropriate 
to expand this language to the monitoring of all pollutants when 
CO2 is used as the diluent and seeks comment on this as 
well. Finally, in the course of reviewing the monitoring language under 
40 CFR part 63, subpart DDDDD, the EPA is proposing to remove several 
requirements for the continuous monitoring of moisture and flow which 
were found to be unnecessary. We also seek comment on these revisions. 
A draft of the language we would propose to accomplish these revisions 
is included in the docket.

VII. 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 OMB for review. Any changes made in response to OMB 
recommendations have been documented in the docket. The RIA for the ICI 
Boilers NESHAP Reconsideration contains the estimated costs, benefits, 
and other impacts associated with this action, and it is available in 
the docket.

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

    This action is expected to be an Executive Order 13771 regulatory 
action. Details on the estimated costs of this proposed rule can be 
found in the EPA's analysis of the potential costs and benefits 
associated with this action, which is the RIA for this proposal.

C. Paperwork Reduction Act (PRA)

    The new information collection activities imposed by this proposed 
rule have been submitted for approval to OMB under the PRA. The 
Information Collection Request (ICR) document that the EPA prepared has 
been assigned EPA ICR number 2028.10. You can find a copy of the ICR in 
the docket for this rule, and it is briefly summarized here.

[[Page 52219]]

    The information requirements are based on notification, 
recordkeeping, and reporting requirements in the NESHAP General 
Provisions (40 CFR part 63, subpart A), which are mandatory for all 
operators subject to national emission standards. These recordkeeping 
and reporting requirements are specifically authorized by section 114 
of the CAA (42 U.S.C. 7414). All information submitted to the EPA 
pursuant to the recordkeeping and reporting requirements for which a 
claim of confidentiality is made is safeguarded according to agency 
policies set forth in 40 CFR part 2, subpart B.
    The proposed amendments change several emission limits as part of 
the EPA's response to the remand granted on December 23, 2016, by the 
D.C. Circuit. The changes result in more stringent emission limits in 
some cases, which is expected to require additional recordkeeping and 
reporting burden. This increase is a result of additional monitoring 
and control devices anticipated to be installed to comply with the more 
stringent emission limits in the proposed amendments. With additional 
control devices, comes additional control device parametric monitoring, 
or in the case of CO, continuous emissions monitoring, and the 
associated records of that monitoring that must be maintained on-site 
and reported. Over the next 3 years, approximately 25 respondents 
operating existing large solid fuel-fired boilers and three respondents 
operating new solid fuel-fired boilers will be impacted by the new 
requirements under the standard as a result of these amendments. In 
addition to the costs to install and maintain records of additional 
monitoring equipment, the ICR details other additional record keeping 
and reporting burden changing records associated with adjusting 
operating parameter limit values, modifying monitoring plans, and 
familiarizing themselves with the changes in the proposed amendments.
    Respondents/affected entities: Owners or operators of ICI boilers 
and process heaters.
    Respondent's obligation to respond: Mandatory, 40 CFR part 63.
    Estimated number of respondents: 28.
    Frequency of response: Semi-annual, annual, periodic.
    Total estimated burden: 1,080 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $307,000 (per year), includes $180,000 
annualized capital or operation and maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates, and any suggested methods 
for minimizing respondent burden to the EPA using the docket identified 
at the beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule.

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. This 
action will not impose any requirements on small entities. Of the 26 
entities determined to be impacted by this action, only one is a small 
entity. This small entity is expected to not incur any costs associated 
with this action. More information on these small entity impacts is 
available in the RIA for this proposal.

E. Unfunded Mandates Reform Act (UMRA)

    This action does not contain any unfunded mandate 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. The action 
affects private industry and does not impose economic costs on State or 
local governments.

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 not have substantial direct effects on 
tribal governments, on the relationship between the federal government 
and Indian tribes, or on the distribution of power and responsibilities 
between the federal government and Indian tribes, as specified in 
Executive Order 13175. Thus, Executive Order 13175 does not apply to 
this action.

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

    The EPA interprets Executive Order 13045 as applying to those 
regulatory actions that concern environmental health or safety risks 
that the EPA has reason to believe may disproportionately affect 
children, per the definition of ``covered regulatory action'' in 
section 2-202 of the Executive Order. This action is not subject to 
Executive Order 13045 because it does not concern an environmental 
health risk or safety risk.

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. The energy impacts estimated for this 
proposed rule increased only slightly the energy impacts estimated for 
the March 21, 2011, final rule which was concluded not to be a 
significant regulatory action under Executive Order 13211. Therefore, 
we conclude that this proposed rule, when implemented, is not likely to 
have a significant adverse effect on the supply, distribution, or use 
of energy.

J. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking 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).
    The documentation for this decision is contained in the preamble to 
the March 2011 final rule (see 76 FR 15662). For the March 2011 final 
rule, the EPA determined that the rule would not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it increases the 
level of environmental protection for all affected populations without 
having any disproportionately high and adverse human health or 
environmental effects on any population, including any

[[Page 52220]]

minority or low-income population. Compared to the final rule, the 
proposed amendments are somewhat more stringent for some subcategories 
and, thus, the overall increased health benefits demonstrate that the 
conclusion from the environmental justice analysis conducted for the 
final rule are still valid.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Reporting and recordkeeping requirements.

Andrew Wheeler,
Administrator.

    For the reasons stated in the preamble, 40 CFR part 63 is proposed 
to be amended as follows:

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

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

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

Subpart DDDDD--National Emission Standards For Hazardous Air 
Pollutants For Major Sources: Industrial, Commercial, And 
Institutional Boilers And Process Heaters

0
2. Section 63.7500 is amended by revising paragraph (a) introductory 
text and paragraphs (a)(1), (c), and (e) to read as follows:


Sec.  63.7500   What emission limitations, work practice standards, and 
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) through (3) 
of this section, except as provided in paragraphs (b) through (e) of 
this section. You must meet these requirements at all times the 
affected unit is operating, except as provided in paragraph (f) of this 
section.
    (1) You must meet each emission limit and work practice standard in 
Tables 1 through 3, and 11 through 15 to this subpart that applies to 
your boiler or process heater, for each boiler or process heater at 
your source, except as provided under Sec.  63.7522. The output-based 
emission limits, in units of pounds per million Btu of steam output, in 
Tables 1 or 2 to this subpart are an alternative applicable only to 
boilers and process heaters that generate either steam, cogenerate 
steam with electricity, or both. The output-based emission limits, in 
units of pounds per megawatt-hour, in Tables 1 or 2 to this subpart are 
an alternative applicable only to boilers that generate only 
electricity. Boilers that perform multiple functions (cogeneration and 
electricity generation) or supply steam to common headers would 
calculate a total steam energy output using equation 21 of Sec.  
63.7575 to demonstrate compliance with the output-based emission 
limits, in units of pounds per million Btu of steam output, in Tables 1 
or 2 to this subpart. If you operate a new boiler or process heater, 
you can choose to comply with alternative limits as discussed in 
paragraphs (a)(1)(i) through (a)(1)(iv) of this section, but on or 
after [DATE 3 YEARS AFTER DATE OF PUBLICATION OF FINAL RULE IN THE 
Federal Register], you must comply with the emission limits in Table 1 
to this subpart. If you operate an existing boiler or process heater, 
you can choose to comply with alternative limits as discussed in 
paragraphs (a)(1)(v) of this section, but on or after [DATE 3 YEARS 
AFTER DATE OF PUBLICATION OF FINAL RULE IN THE Federal Register] you 
must comply with the emission limits in Table 2 to this subpart.
    (i) If your boiler or process heater commenced construction or 
reconstruction after June 4, 2010, and before May 20, 2011, you may 
comply with the emission limits in Table 11 or 14 to this subpart until 
January 31, 2016.
    (ii) If your boiler or process heater commenced construction or 
reconstruction on or after May 20, 2011, and before December 23, 2011, 
you may comply with the emission limits in Table 12 or 14 to this 
subpart until January 31, 2016.
    (iii) If your boiler or process heater commenced construction or 
reconstruction on or after December 23, 2011, and before April 1, 2013, 
you may comply with the emission limits in Table 13 or 14 to this 
subpart until January 31, 2016.
    (iv) If you operate a new boiler or process heater, you may comply 
with the emission limits in Table 1 or 14 until you must comply with 
the emission limits in Table 1 to this subpart.
    (v) If you operate an existing boiler or process heater, you may 
comply with the emission limits in Table 2 or 15 until you must comply 
with the emission limits in Table 2 to this subpart.
* * * * *
    (c) Limited-use boilers and process heaters must complete a tune-up 
every 5 years as specified in Sec.  63.7540. They are not subject to 
the emission limits in Tables 1 and 2 or 11 through 15 to this subpart, 
the annual tune-up, or the energy assessment requirements in Table 3 to 
this subpart, or the operating limits in Table 4 to this subpart.
* * * * *
    (e) Boilers and process heaters in the units designed to burn gas 1 
fuels subcategory with a heat input capacity of less than or equal to 5 
million Btu per hour must complete a tune-up every 5 years as specified 
in Sec.  63.7540. Boilers and process heaters in the units designed to 
burn gas 1 fuels subcategory with a heat input capacity greater than 5 
million Btu per hour and less than 10 million Btu per hour must 
complete a tune-up every 2 years as specified in Sec.  63.7540. Boilers 
and process heaters in the units designed to burn gas 1 fuels 
subcategory are not subject to the emission limits in Tables 1 and 2 or 
11 through 15 to this subpart, or the operating limits in Table 4 to 
this subpart.
* * * * *
0
3. Section 63.7505 is amended by revising paragraph (c) to read as 
follows:


Sec.  63.7505  What are my general requirements for complying with this 
subpart?

* * * * *
    (c) You must demonstrate compliance with all applicable emission 
limits using performance stack testing, fuel analysis, or continuous 
monitoring systems (CMS), including a continuous emission monitoring 
system (CEMS), continuous opacity monitoring system (COMS), continuous 
parameter monitoring system (CPMS), or particulate matter continuous 
parameter monitoring system (PM CPMS), where applicable. You may 
demonstrate compliance with the applicable emission limit for hydrogen 
chloride (HCl), mercury, or total selected metals (TSM) using fuel 
analysis if the emission rate calculated according to Sec.  63.7530(c) 
is less than the applicable emission limit. For gaseous fuels, you may 
not use fuel analyses to comply with the TSM alternative standard or 
the HCl standard. Otherwise, you must demonstrate compliance for HCl, 
mercury, or TSM using performance stack testing, if subject to an 
applicable emission limit listed in Tables 1, 2, or 11 through 15 to 
this subpart.
* * * * *
0
4. Section 63.7510 is amended by revising paragraph (a) introductory 
text and paragraphs (b), (c), (f), and (j) to read as follows:

[[Page 52221]]

Sec.  63.7510   What are my initial compliance requirements and by what 
date must I conduct them?

    (a) For each boiler or process heater that is required or that you 
elect to demonstrate compliance with any of the applicable emission 
limits in Tables 1 or 2 or 11 through 15 of this subpart through 
performance (stack) testing, your initial compliance requirements 
include all the following:
* * * * *
    (b) For each boiler or process heater that you elect to demonstrate 
compliance with the applicable emission limits in Tables 1 or 2 or 11 
through 15 to this subpart for HCl, mercury, or TSM through fuel 
analysis, your initial compliance requirement is to conduct a fuel 
analysis for each type of fuel burned in your boiler or process heater 
according to Sec.  63.7521 and Table 6 to this subpart and establish 
operating limits according to Sec.  63.7530 and Table 8 to this 
subpart. The fuels described in paragraph (a)(2)(i) and (ii) of this 
section are exempt from these fuel analysis and operating limit 
requirements. The fuels described in paragraph (a)(2)(ii) of this 
section are exempt from the chloride fuel analysis and operating limit 
requirements. Boilers and process heaters that use a CEMS for mercury 
or HCl are exempt from the performance testing and operating limit 
requirements specified in paragraph (a) of this section for the HAP for 
which CEMS are used.
    (c) If your boiler or process heater is subject to a carbon 
monoxide (CO) limit, your initial compliance demonstration for CO is to 
conduct a performance test for CO according to Table 5 to this subpart 
or conduct a performance evaluation of your continuous CO monitor, if 
applicable, according to Sec.  63.7525(a). Boilers and process heaters 
that use a CO CEMS to comply with the applicable alternative CO CEMS 
emission standard listed in Tables 1, 2, or 11 through 15 to this 
subpart, as specified in Sec.  63.7525(a), are exempt from the initial 
CO performance testing and oxygen concentration operating limit 
requirements specified in paragraph (a) of this section.
* * * * *
    (f) For new or reconstructed affected sources (as defined in Sec.  
63.7490), you must complete the initial compliance demonstration with 
the emission limits no later than July 30, 2013, or within 180 days 
after startup of the source, whichever is later.
    (1) If you are demonstrating compliance with an emission limit in 
Tables 11 through 13 to this subpart that is less stringent (that is, 
higher) than the applicable emission limit in Table 14 to this subpart, 
you must demonstrate compliance with the applicable emission limit in 
Table 14 no later than July 29, 2016.
    (2) If you are demonstrating compliance with an emission limit in 
Table 14 to this subpart that is less stringent (that is, higher) than 
the applicable emission limit in Table 1 to this subpart, you must 
demonstrate compliance with the applicable emission limit in Table 1 to 
this subpart no later than [date 3 years after date of publication of 
final rule in the Federal Register].
* * * * *
    (j) For existing affected sources (as defined in Sec.  63.7490) 
that have not operated between the effective date of the rule and the 
compliance date that is specified for your source in Sec.  63.7495, you 
must complete the initial compliance demonstration, if subject to the 
emission limits in Tables 2 or 14, to this subpart, as applicable, as 
specified in paragraphs (a) through (d) of this section, no later than 
180 days after the re-start of the affected source and according to the 
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this 
subpart. You must complete an initial tune-up by following the 
procedures described in Sec.  63.7540(a)(10)(i) through (vi) no later 
than 30 days after the re-start of the affected source and, if 
applicable, complete the one-time energy assessment specified in Table 
3 to this subpart, no later than the compliance date specified in Sec.  
63.7495.
* * * * *
0
5. Section 63.7515 is amended by revising paragraphs (b), (c), (e), 
(g), and (i) to read as follows:


Sec.  63.7515   When must I conduct subsequent performance tests, fuel 
analyses, or tune-ups?

* * * * *
    (b) If your performance tests for a given pollutant for at least 2 
consecutive years show that your emissions are at or below 75 percent 
of the emission limit (or, in limited instances as specified in Tables 
1 and 2 or 11 through 15 to this subpart, at or below the emission 
limit) for the pollutant, and if there are no changes in the operation 
of the individual boiler or process heater or air pollution control 
equipment that could increase emissions, you may choose to conduct 
performance tests for the pollutant every third year. Each such 
performance test must be conducted no more than 37 months after the 
previous performance test. If you elect to demonstrate compliance using 
emission averaging under Sec.  63.7522, you must continue to conduct 
performance tests annually. The requirement to test at maximum chloride 
input level is waived unless the stack test is conducted for HCl. The 
requirement to test at maximum mercury input level is waived unless the 
stack test is conducted for mercury. The requirement to test at maximum 
TSM input level is waived unless the stack test is conducted for TSM.
    (c) If a performance test shows emissions exceeded the emission 
limit or 75 percent of the emission limit (as specified in Tables 1 and 
2 or 11 through 15 to this subpart) for a pollutant, you must conduct 
annual performance tests for that pollutant until all performance tests 
over a consecutive 2-year period meet the required level (at or below 
75 percent of the emission limit, as specified in Tables 1 and 2 or 11 
through 15 to this subpart).
* * * * *
    (e) If you demonstrate compliance with the mercury, HCl, or TSM 
based on fuel analysis, you must conduct a monthly fuel analysis 
according to Sec.  63.7521 for each type of fuel burned that is subject 
to an emission limit in Tables 1, 2, or 11 through 15 to this subpart. 
You may comply with this monthly requirement by completing the fuel 
analysis any time within the calendar month as long as the analysis is 
separated from the previous analysis by at least 14 calendar days. If 
you burn a new type of fuel, you must conduct a fuel analysis before 
burning the new type of fuel in your boiler or process heater. You must 
still meet all applicable continuous compliance requirements in Sec.  
63.7540. If each of 12 consecutive monthly fuel analyses demonstrates 
75 percent or less of the compliance level, you may decrease the fuel 
analysis frequency to quarterly for that fuel. If any quarterly sample 
exceeds 75 percent of the compliance level or you begin burning a new 
type of fuel, you must return to monthly monitoring for that fuel, 
until 12 months of fuel analyses are again less than 75 percent of the 
compliance level. If sampling is conducted on 1 day per month, samples 
should be no less than 14 days apart, but if multiple samples are taken 
per month, the 14-day restriction does not apply.
* * * * *
    (g) For affected sources (as defined in Sec.  63.7490) that have 
not operated since the previous compliance demonstration and more than 
1 year has passed since the previous compliance demonstration, you must 
complete the subsequent compliance demonstration, if subject to the 
emission limits in Tables 1, 2, or 11 through 15 to this subpart, no 
later than

[[Page 52222]]

180 days after the re-start of the affected source and according to the 
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this 
subpart. You must complete a subsequent tune-up by following the 
procedures described in Sec.  63.7540(a)(10)(i) through (vi) and the 
schedule described in Sec.  63.7540(a)(13) for units that are not 
operating at the time of their scheduled tune-up.
* * * * *
    (i) If you operate a CO CEMS that meets the Performance 
Specifications outlined in Sec.  63.7525(a)(3) of this subpart to 
demonstrate compliance with the applicable alternative CO CEMS emission 
standard listed in Tables 1, 2, or 11 through 15 to this subpart, you 
are not required to conduct CO performance tests and are not subject to 
the oxygen concentration operating limit requirement specified in Sec.  
63.7510(a).
0
6. Section 63.7520 is amended by revising paragraph (d) to read as 
follows:


Sec.  63.7520  What stack tests and procedures must I use?

* * * * *
    (d) You must conduct a minimum of three separate test runs for each 
performance test required in this section, as specified in Sec.  
63.7(e)(3). Each test run must comply with the minimum applicable 
sampling times or volumes specified in Tables 1 and 2 or 11 through 15 
to this subpart.
* * * * *
0
7. Section 63.7521 is amended by revising paragraphs (a) and (c)(1)(ii) 
to read as follows:


Sec.  63.7521   What fuel analyses, fuel specification, and procedures 
must I use?

    (a) For solid and liquid fuels, you must conduct fuel analyses for 
chloride and mercury according to the procedures in paragraphs (b) 
through (e) of this section and Table 6 to this subpart, as applicable. 
For solid fuels and liquid fuels, you must also conduct fuel analyses 
for TSM if you are opting to comply with the TSM alternative standard. 
For gas 2 (other) fuels, you must conduct fuel analyses for mercury 
according to the procedures in paragraphs (b) through (e) of this 
section and Table 6 to this subpart, as applicable. For gaseous fuels, 
you may not use fuel analyses to comply with the TSM alternative 
standard or the HCl standard. For purposes of complying with this 
section, a fuel gas system that consists of multiple gaseous fuels 
collected and mixed with each other is considered a single fuel type 
and sampling and analysis is only required on the combined fuel gas 
system that will feed the boiler or process heater. Sampling and 
analysis of the individual gaseous streams prior to combining is not 
required. You are not required to conduct fuel analyses for fuels used 
for only startup, unit shutdown, and transient flame stability 
purposes. You are required to conduct fuel analyses only for fuels and 
units that are subject to emission limits for mercury, HCl, or TSM in 
Tables 1 and 2 or 11 through 15 to this subpart. Gaseous and liquid 
fuels are exempt from the sampling requirements in paragraphs (c) and 
(d) of this section.
* * * * *
    (c) * * *
    (1) * * *
    (ii) Each composite sample will consist of a minimum of three 
samples collected at approximately equal intervals during the testing 
period for sampling during performance stack testing.
* * * * *
0
8. Section 63.7522 is amended by revising paragraph (b) introductory 
text and paragraphs (d), (e)(1), (2), (h), and (j)(1) to read as 
follows:


Sec.  63.7522  Can I use emissions averaging to comply with this 
subpart?

* * * * *
    (b) For a group of two or more existing boilers or process heaters 
in the same subcategory that each vent to a separate stack, you may 
average PM (or TSM), HCl, or mercury emissions among existing units to 
demonstrate compliance with the limits in Table 2 or 15 to this subpart 
as specified in paragraph (b)(1) through (3) of this section, if you 
satisfy the requirements in paragraphs (c) through (g) of this section.
* * * * *
    (d) The averaged emissions rate from the existing boilers and 
process heaters participating in the emissions averaging option must 
not exceed 90 percent of the limits in Table 2 or 15 to this subpart at 
all times the affected units are subject to numeric emission limits 
following the compliance date specified in Sec.  63.7495.
    (e) * * *
    (1) You must use Equation 1a or 1b or 1c of this section to 
demonstrate that the PM (or TSM), HCl, or mercury emissions from all 
existing units participating in the emissions averaging option for that 
pollutant do not exceed the emission limits in Table 2 or 15 to this 
subpart. Use Equation 1a if you are complying with the emission limits 
on a heat input basis, use Equation 1b if you are complying with the 
emission limits on a steam generation (output) basis, and use Equation 
1c if you are complying with the emission limits on a electric 
generation (output) basis.
[GRAPHIC] [TIFF OMITTED] TP24AU20.000

Where:

AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of heat input. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM using the applicable equation in Sec.  
63.7530(c).
Hm = Maximum rated heat input capacity of unit, i, in units of 
million Btu per hour.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TP24AU20.001

Where:

AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per million Btu of steam output.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of steam output. Determine the 
emission rate for PM (or TSM), HCl, or mercury by

[[Page 52223]]

performance testing according to Table 5 to this subpart, or by fuel 
analysis for HCl or mercury or TSM using the applicable equation in 
Sec.  63.7530(c). If you are taking credit for energy conservation 
measures from a unit according to Sec.  63.7533, use the adjusted 
emission level for that unit, Eadj, determined according to Sec.  
63.7533 for that unit.
So = Maximum steam output capacity of unit, i, in units of million 
Btu per hour, as defined in Sec.  63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TP24AU20.002

Where:

AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per megawatt hour.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per megawatt hour. Determine the emission rate for 
PM (or TSM), HCl, or mercury by performance testing according to 
Table 5 to this subpart, or by fuel analysis for HCl or mercury or 
TSM using the applicable equation in Sec.  63.7530(c). If you are 
taking credit for energy conservation measures from a unit according 
to Sec.  63.7533, use the adjusted emission level for that unit, 
Eadj, determined according to Sec.  63.7533 for that unit.
Eo = Maximum electric generating output capacity of unit, i, in 
units of megawatt hour, as defined in Sec.  63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.

    (2) If you are not capable of determining the maximum rated heat 
input capacity of one or more boilers that generate steam, you may use 
Equation 2 of this section as an alternative to using Equation 1a of 
this section to demonstrate that the PM (or TSM), HCl, or mercury 
emissions from all existing units participating in the emissions 
averaging option do not exceed the emission limits for that pollutant 
in Table 2 or 15 to this subpart that are in pounds per million Btu of 
heat input.
[GRAPHIC] [TIFF OMITTED] TP24AU20.003

Where:

AveWeightedEmissions = Average weighted emission level for PM (or 
TSM), HCl, or mercury, in units of pounds per million Btu of heat 
input.
Er = Emission rate (as determined during the most recent compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of heat input. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM using the applicable equation in Sec.  
63.7530(c).
Sm = Maximum steam generation capacity by unit, i, in units of 
pounds per hour.
Cfi = Conversion factor, calculated from the most recent compliance 
test, in units of million Btu of heat input per pounds of steam 
generated for unit, i.
1.1 = Required discount factor.
* * * * *
    (h) For a group of two or more existing affected units, each of 
which vents through a single common stack, you may average PM (or TSM), 
HCl, or mercury emissions to demonstrate compliance with the limits for 
that pollutant in Table 2 or 15 to this subpart if you satisfy the 
requirements in paragraph (i) or (j) of this section.
* * * * *
    (j) * * *
    (1) Conduct performance tests according to procedures specified in 
Sec.  63.7520 in the common stack if affected units from other 
subcategories vent to the common stack. The emission limits that the 
group must comply with are determined by the use of Equation 6 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP24AU20.004

Where:

En = HAP emission limit, pounds per million British thermal units 
(lb/MMBtu) or parts per million (ppm).
ELi = Appropriate emission limit from Table 2 or 15 to this subpart 
for unit i, in units of lb/MMBtu or ppm.
Hi = Heat input from unit i, MMBtu.
* * * * *
0
9. Section 63.7525 is amended by revising paragraphs (a), (2), (2)(iv), 
(l), and (m) introductory text to read as follows:


Sec.  63.7525   What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If your boiler or process heater is subject to a CO emission 
limit in Tables 1, 2, or 11 through 15 to this subpart, you must 
install, operate, and maintain an oxygen analyzer system, as defined in 
Sec.  63.7575, or install, certify, operate and maintain continuous 
emission monitoring systems for CO and oxygen (or carbon dioxide 
(CO2)) according to the procedures in paragraphs (a)(1) 
through (6) of this section.
* * * * *
    (2) To demonstrate compliance with the applicable alternative CO 
CEMS emission standard listed in Tables 1, 2, or 11 through 15 to this 
subpart, you must install, certify, operate, and maintain a CO CEMS and 
an oxygen analyzer according to the applicable procedures under 
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B; 
part 75 of this chapter (if an CO2 analyzer is used); the 
site-specific monitoring plan developed according to Sec.  63.7505(d); 
and the requirements in Sec.  63.7540(a)(8) and paragraph (a) of this 
section. Any boiler or process heater that has a CO CEMS that is 
compliant with Performance Specification 4, 4A, or 4B at 40 CFR part 
60, appendix B, a site-specific monitoring plan developed according to 
Sec.  63.7505(d), and the requirements in Sec.  63.7540(a)(8) and 
paragraph (a) of this section must use the CO CEMS to comply with the 
applicable alternative CO CEMS emission standard listed in Tables 1, 2, 
or 11 through 15 to this subpart.
* * * * *
    (iv) Any CO CEMS that does not comply with Sec.  63.7525(a) cannot 
be used to meet any requirement in this subpart to demonstrate 
compliance with a CO emission limit listed in Tables 1, 2, or 11 
through 15 to this subpart.
* * * * *
    (l) For each unit for which you decide to demonstrate compliance 
with the mercury or HCl emissions limits in Tables 1 or 2 or 11 through 
15 of this subpart by use of a CEMS for mercury or HCl, you must 
install, certify, maintain, and operate a CEMS measuring emissions 
discharged to the

[[Page 52224]]

atmosphere and record the output of the system as specified in 
paragraphs (l)(1) through (8) of this section. For HCl, this option for 
an affected unit takes effect on the date a final performance 
specification for a HCl CEMS is published in the Federal Register or 
the date of approval of a site-specific monitoring plan.
    (m) If your unit is subject to a HCl emission limit in Tables 1, 2, 
or 11 through 15 of this subpart and you have an acid gas wet scrubber 
or dry sorbent injection control technology and you elect to use an 
SO2 CEMS to demonstrate continuous compliance with the HCl 
emission limit, you must install the monitor at the outlet of the 
boiler or process heater, downstream of all emission control devices, 
and you must install, certify, operate, and maintain the CEMS according 
to either part 60 or part 75 of this chapter.
* * * * *
0
10. Section 63.7530 is amended by revising paragraphs (b)(4)(ii)(E) and 
(iii) and the introductory text of paragraph (h) to read as follows:


Sec.  63.7530   How do I demonstrate initial compliance with the 
emission limitations, fuel specifications and work practice standards?

* * * * *
    (b) * * *
    (4) * * *
    (ii) * * *
    (E) Use EPA Method 5 of appendix A to part 60 of this chapter to 
determine PM emissions. For each performance test, conduct three 
separate runs under the conditions that exist when the affected source 
is operating at the highest load or capacity level reasonably expected 
to occur. Conduct each test run to collect a minimum sample volume 
specified in Tables 1, 2, or 11 through 15 to this subpart, as 
applicable, for determining compliance with a new source limit or an 
existing source limit. Calculate the average of the results from three 
runs to determine compliance. You need not determine the PM collected 
in the impingers (``back half'') of the Method 5 particulate sampling 
train to demonstrate compliance with the PM standards of this subpart. 
This shall not preclude the permitting authority from requiring a 
determination of the ``back half'' for other purposes.
* * * * *
    (iii) For a particulate wet scrubber, you must establish the 
minimum pressure drop and liquid flow rate as defined in Sec.  63.7575, 
as your operating limits during the three-run performance test during 
which you demonstrate compliance with your applicable limit. If you use 
a wet scrubber and you conduct separate performance tests for PM and 
TSM emissions, you must establish one set of minimum scrubber liquid 
flow rate and pressure drop operating limits. If you conduct multiple 
performance tests, you must set the minimum liquid flow rate and 
pressure drop operating limits at the higher of the minimum values 
established during the performance tests.
* * * * *
    (h) If you own or operate a unit subject to emission limits in 
Tables 1 or 2 or 11 through 15 to this subpart, you must meet the work 
practice standard according to Table 3 of this subpart. During startup 
and shutdown, you must only follow the work practice standards 
according to items 5 and 6 of Table 3 of this subpart.
* * * * *
0
11. Section 63.7533 is amended by revising paragraphs (a), (e), and (f) 
to read as follows:


Sec.  63.7533  Can I use efficiency credits earned from implementation 
of energy conservation measures to comply with this subpart?

    (a) If you elect to comply with the alternative equivalent output-
based emission limits, instead of the heat input-based limits listed in 
Table 2 or 15 to this subpart, and you want to take credit for 
implementing energy conservation measures identified in an energy 
assessment, you may demonstrate compliance using efficiency credits 
according to the procedures in this section. You may use this 
compliance approach for an existing affected boiler for demonstrating 
initial compliance according to Sec.  63.7522(e) and for demonstrating 
monthly compliance according to Sec.  63.7522(f). Owners or operators 
using this compliance approach must establish an emissions benchmark, 
calculate and document the efficiency credits, develop an 
Implementation Plan, comply with the general reporting requirements, 
and apply the efficiency credit according to the procedures in 
paragraphs (b) through (f) of this section. You cannot use this 
compliance approach for a new or reconstructed affected boiler. 
Additional guidance from the Department of Energy on efficiency credits 
is available at: https://www.epa.gov/ttn/atw/boiler/boilerpg.html.
* * * * *
    (e) The emissions rate as calculated using Equation 20 of this 
section from each existing boiler participating in the efficiency 
credit option must be in compliance with the limits in Table 2 or 15 to 
this subpart at all times the affected unit is subject to numeric 
emission limits, following the compliance date specified in Sec.  
63.7495.
    (f) You must use Equation 20 of this section to demonstrate initial 
compliance by demonstrating that the emissions from the affected boiler 
participating in the efficiency credit compliance approach do not 
exceed the emission limits in Table 2 or 15 to this subpart.
[GRAPHIC] [TIFF OMITTED] TP24AU20.005

Where:

Eadj = Emission level adjusted by applying the efficiency 
credits earned, lb per million Btu steam output (or lb per MWh) for 
the affected boiler.
Em = Emissions measured during the performance test, lb 
per million Btu steam output (or lb per MWh) for the affected 
boiler.
ECredits = Efficiency credits from Equation 19 for the affected 
boiler.
* * * * *
0
12. Section 63.7540 is amended by:
0
a. Revising paragraphs (a), (8), and (19) introductory text; and
0
b. Revising paragraphs (a)(8)(ii), (9), and (b).
    The revisions read as follows:


Sec.  63.7540   How do I demonstrate continuous compliance with the 
emission limitations, fuel specifications and work practice standards?

    (a) You must demonstrate continuous compliance with each emission 
limit in Tables 1 and 2 or 11 through 15 to this subpart, the work 
practice standards in Table 3 to this subpart, and the operating limits 
in Table 4 to this subpart that applies to you according to the methods 
specified in Table 8 to this subpart and paragraphs (a)(1) through (19) 
of this section.
* * * * *
    (8) To demonstrate compliance with the applicable alternative CO 
CEMS emission limit listed in Tables 1, 2, or 11 through 15 to this 
subpart, you must meet the requirements in paragraphs (a)(8)(i) through 
(iv) of this section.
* * * * *
    (ii) Maintain a CO emission level below or at your applicable 
alternative CO CEMS-based standard in Tables 1 or 2 or 11 through 15 to 
this subpart at all times the affected unit is subject to numeric 
emission limits.
* * * * *
    (9) The owner or operator of a boiler or process heater using a PM 
CPMS or a PM CEMS to meet requirements of this subpart shall install, 
certify (PM CEMS only), operate, and maintain the PM CPMS or PM CEMS in 
accordance with

[[Page 52225]]

your site-specific monitoring plan as required in Sec.  63.7505(d).
* * * * *
    (19) If you choose to comply with the PM filterable emissions limit 
by using PM CEMS you must install, certify, operate, and maintain a PM 
CEMS and record the output of the PM CEMS as specified in paragraphs 
(a)(19)(i) through (vii) of this section. The compliance limit will be 
expressed as a 30-day rolling average of the numerical emissions limit 
value applicable for your unit in Tables 1 or 2 or 11 through 15 of 
this subpart.
* * * * *
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 through 4 or 11 through 
15 to this subpart that apply to you. These instances are deviations 
from the emission limits or operating limits, respectively, in this 
subpart. These deviations must be reported according to the 
requirements in Sec.  63.7550.
* * * * *
0
13. Section 63.7545 is amended by revising paragraph (e)(3) to read as 
follows:


Sec.  63.7545   What notifications must I submit and when?

* * * * *
    (e) * * *
    (3) A summary of the maximum CO emission levels recorded during the 
performance test to show that you have met any applicable emission 
standard in Tables 1, 2, or 11 through 15 to this subpart, if you are 
not using a CO CEMS to demonstrate compliance.
* * * * *
0
14. Section 63.7555 is amended by revising paragraph (d) introductory 
text and paragraph (5) to read as follows:


Sec.  63.7555   What records must I keep?

* * * * *
    (d) For each boiler or process heater subject to an emission limit 
in Tables 1, 2, or 11 through 15 to this subpart, you must also keep 
the applicable records in paragraphs (d)(1) through (11) of this 
section.
* * * * *
    (5) If, consistent with Sec.  63.7515(b), you choose to stack test 
less frequently than annually, you must keep a record that documents 
that your emissions in the previous stack test(s) were less than 75 
percent of the applicable emission limit (or, in specific instances 
noted in Tables 1 and 2 or 11 through 15 to this subpart, less than the 
applicable emission limit), and document that there was no change in 
source operations including fuel composition and operation of air 
pollution control equipment that would cause emissions of the relevant 
pollutant to increase within the past year.
* * * * *
0
15. Section 63.7575 is amended by:
0
a. Adding, in alphabetical order, a definition for ``12-month rolling 
average'';
0
b. Revising the definition of ``Other gas 1 fuel''; and
0
c. Revising paragraphs (3) and (4) under the definition of ``Steam 
output.''
    The additions and revisions read as follows:


Sec.  63.7575   What definitions apply to this subpart?

* * * * *
    12-month rolling average means the arithmetic mean of the previous 
12 months of valid fuel analysis data. The 12 months should be 
consecutive, but not necessarily continuous if operations were 
intermittent.
* * * * *
    Other gas 1 fuel means a gaseous fuel that is not natural gas or 
refinery gas and does not exceed a maximum mercury concentration of 40 
micrograms/cubic meters of gas.
* * * * *
    Steam output * * *
* * * * *
    (3) For a boiler that generates only electricity, the alternate 
output-based emission limits would be the appropriate emission limit 
from Table 1 or 2 or 14 or 15 of this subpart in units of pounds per 
million Btu heat input (lb per MWh).
    (4) For a boiler that performs multiple functions and produces 
steam to be used for any combination of paragraphs (1), (2) and (3) of 
this definition that includes electricity generation of paragraph (3) 
of this definition, the total energy output, in terms of MMBtu of steam 
output, is the sum of the energy content of steam sent directly to the 
process and/or used for heating (S1), the energy content of 
turbine steam sent to process plus energy in electricity according to 
paragraph (2) of this definition (S2), and the energy 
content of electricity generated by a electricity only turbine as 
paragraph (3) of this definition (MW3) and would be 
calculated using Equation 21 of this section. In the case of boilers 
supplying steam to one or more common headers, S1, 
S2, and MW(3) for each boiler would be calculated 
based on the its (steam energy) contribution (fraction of total steam 
energy) to the common header.
[GRAPHIC] [TIFF OMITTED] TP24AU20.006

Where:

SOM = Total steam output for multi-function boiler, MMBtu
S1 = Energy content of steam sent directly to the process 
and/or used for heating, MMBtu
S2 = Energy content of turbine steam sent to the process 
plus energy in electricity according to (2) above, MMBtu
MW(3) = Electricity generated according to paragraph (3) 
of this definition, MWh
CFn = Conversion factor for the appropriate subcategory for 
converting electricity generated according to paragraph (3) of this 
definition to equivalent steam energy, MMBtu/MWh
CFn for emission limits for boilers in the unit designed to burn 
solid fuel subcategory = 10.8
CFn PM and CO emission limits for boilers in one of the 
subcategories of units designed to burn coal = 11.7
CFn PM and CO emission limits for boilers in one of the 
subcategories of units designed to burn biomass = 12.1
CFn for emission limits for boilers in one of the subcategories of 
units designed to burn liquid fuel = 11.2
CFn for emission limits for boilers in the unit designed to burn gas 
2 (other) subcategory = 6.2
* * * * *
0
16. Table 1 to subpart DDDDD is amended to read as follows:

[[Page 52226]]



    Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
  As stated in Sec.   63.7500, you must comply with the following applicable emission limits: [Units with heat
                              input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                           Or the emissions
                                                      The emissions must    must not exceed
                                                        not exceed the       the following        Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  3.0E-04 lb per      4.1E-04 lb per      For M26A, collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 3.9E-03   dscm per run; for
                                                                           lb per MWh.         M26 collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  8.0E-07 \a\ lb per  8.7E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 1.1E-05   per run; for M30A
                                                                           \a\ lb per MWh.     or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 4 dscm.
2. Units designed to burn coal/   a. Filterable PM    1.1E-03 lb per      1.1E-03 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.3E-    output or 1.4E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 2.9E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. Carbon monoxide  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid       (CO) (or CEMS).     on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3-     or 1.4 lb per
                                                       percent oxygen, 3-  MWh; three-run
                                                       run average; or     average.
                                                       (320 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
4. Stokers/others designed to     a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen, 3-  MWh; three-run
                                                       run average; or     average.
                                                       (340 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen, 3-  MWh; three-run
                                                       run average; or     average.
                                                       (230 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.2E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3-     output or 1.5 lb
 fossil fuel.                                          percent oxygen, 3-  per MWh; three-
                                                       run average; or     run average.
                                                       (150 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  590 ppm by volume   6.1E-01 lb per      1 hr minimum
 designed to burn wet biomass                          on a dry basis      MMBtu of steam      sampling time.
 fuel.                                                 corrected to 3-     output or 6.5 lb
                                                       percent oxygen, 3-  per MWh; three-
                                                       run average; or     run average.
                                                       (390 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    1.3E-02 lb per      1.4E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.6E-    output or 1.9E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 3.7E-04
                                                                           lb per MWh).
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.3E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3-     output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.0E-02 lb per      3.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.0E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.2E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 7.0E-02
                                                                           lb per MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   1.3E-01 lb per      1 hr minimum
 to burn biomass/bio-based                             on a dry basis      MMBtu of steam      sampling time.
 solids.                                               corrected to 3-     output or 1.5 lb
                                                       percent oxygen, 3-  per MWh; three-
                                                       run average; or     run average.
                                                       (310 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    4.1E-03 lb per      5.0E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (8.4E-    output or 5.8E-02   run.
                                                       06 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (1.1E-05 \a\ lb
                                                       input).             per MMBtu of
                                                                           steam output or
                                                                           1.2E-04 \a\ lb
                                                                           per MWh).
10. Suspension burners designed   a. CO (or CEMS)...  220 ppm by volume   0.18 lb per MMBtu   1 hr minimum
 to burn biomass/bio-based                             on a dry basis      of steam output     sampling time.
 solids.                                               corrected to 3-     or 2.5 lb per
                                                       percent oxygen, 3-  MWh; three-run
                                                       run average; or     average.
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).

[[Page 52227]]

 
                                  b. Filterable PM    3.0E-02 lb per      3.1E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (8.0E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (8.1E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 1.2E-01
                                                                           lb per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  330 ppm by volume   3.5E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solids.                                         corrected to 3-     output or 3.6 lb
                                                       percent oxygen, 3-  per MWh; three-
                                                       run average; or     run average.
                                                       (520 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).
                                  b. Filterable PM    2.5E-03 lb per      3.4E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (3.9E-    output or 3.5E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.2E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 5.5E-04
                                                                           lb per MWh).
12. Fuel cell units designed to   a. CO.............  910 ppm by volume   1.1 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solids.                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0E+01 lb per
                                                       percent oxygen.     MWh.
                                  b. Filterable PM    1.1E-02 lb per      2.0E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.9E-    output or 1.6E-01   run.
                                                       05 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (5.1E-05 lb per
                                                       input).             MMBtu of steam
                                                                           output or 4.1E-04
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  180 ppm by volume   0.22 lb per MMBtu   1 hr minimum
 boiler designed to burn biomass/                      on a dry basis      of steam output     sampling time.
 bio-based solids.                                     corrected to 3-     or 2.0 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    2.6E-02 lb per      3.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (4.4E-    output or 3.7E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 6.2E-03
                                                                           lb per MWh).
14. Units designed to burn        a. HCl............  7.0E-05 lb per      7.7E-05 lb per      For M26A: Collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 9.7E-04   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  4.8E-07 \a\ lb per  5.3E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 6.7E-06   per run; for M30A
                                                                           \a\ lb per MWh.     or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 4 dscm.
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average.  average.
                                  b. Filterable PM    1.9E-03 lb per      2.1E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (6.1E-    output or 2.7E-02   run.
                                                       06 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (6.7E-6 lb per
                                                                           MMBtu of steam
                                                                           output or 8.5E-5
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per MWh.
                                                       percent oxygen.
                                  b. Filterable PM    1.1E-03 \a\ lb per  1.2E-03 \a\ lb per  Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.9E-    output or 1.6E-02   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (3.2E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           4.0E-04 lb per
                                                                           MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3-     or 1.4 lb per
                                                       percent oxygen, 3-  MWh; three-run
                                                       run average based   average.
                                                       on stack test.
                                  b. Filterable PM    2.3E-02 lb per      2.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 4 dscm per
                                                       input; or (8.6E-    output or 3.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (9.4E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 1.2E-02
                                                                           lb per MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, Collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 3 dscm.

[[Page 52228]]

 
                                  d. Filterable PM    7.3E-03 lb per      1.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.1E-    output or 7.6E-02   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
  for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
  according to Sec.   63.7515 if all of the other provisions of Sec.   63.7515 are met. For all other pollutants
  that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
  years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
  testing.
\b\ Incorporated by reference, see Sec.   63.14.
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
  reconstruction after June 4, 2010, and before April 1, 2013, you may comply with the emission limits in Tables
  11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, but before [date 3 years
  after date of publication of final rule in the Federal Register] you may comply with the emission limits in
  Table 14 to this subpart. On and after [date 3 years after date of publication of final rule in the Federal
  Register], you must comply with the emission limits in Table 1 to this subpart.
\d\ An owner or operator may request an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place
  of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account
  that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must
  account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone
  injection, scrubber media, etc.

0
17. Table 2 to subpart DDDDD is amended to read as follows:

          Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters
  As stated in Sec.   63.7500, you must comply with the following applicable emission limits: [Units with heat
                              input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                          The emissions must
                                                      The emissions must    not exceed the
                                                        not exceed the         following          Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  2.0E-02 lb per      2.3E-02 lb per      For M26A, Collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.26 lb   dscm per run; for
                                                                           per MWh.            M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  5.4E-06 lb per      6.2E-06 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 6.9E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 3 dscm.
2. Units design to burn coal/     a. Filterable PM    3.9E-02 lb per      4.1E-02 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.3E-    output or 4.8E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.6E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 6.5E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid                           on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (320
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
4. Stokers/others designed to     a. CO (or CEMS)...  150 ppm by volume   0.14 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.6 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (340
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (230
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.3E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3-     output or 1.5 lb
 fossil fuel.                                          percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (150
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  1,100 ppm by        1.1 lb per MMBtu    1 hr minimum
 designed to burn wet biomass                          volume on a dry     of steam output     sampling time.
 fuel.                                                 basis corrected     or 13 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or (720
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).

[[Page 52229]]

 
                                  b. Filterable PM    3.4E-02 lb per      4.0E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.0E-    output or 4.8E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.4E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.8E-03
                                                                           lb per MWh).
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.2E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3-     output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.2E-01 lb per      3.7E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (5.0E-    output or 4.5 lb    run.
                                                       03 lb per MMBtu     per MWh; or (5.9E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 7.0E-02 lb per
                                                                           MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  210 ppm by volume   2.1E-01 lb per      1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      MMBtu of steam      sampling time.
                                                       corrected to 3-     output or 2.3 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (310
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
                                  b. Filterable PM    2.1E-02 lb per      2.6E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (6.4E-    output or 0.30 lb   run.
                                                       05 lb per MMBtu     per MWh; or (8.0E-
                                                       of heat input).     05 lb per MMBtu
                                                                           of steam output
                                                                           or 9.0E-04 lb per
                                                                           MWh).
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based solid.                      volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 27 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
                                  b. Filterable PM    4.1E-02 lb per      4.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (8.0E-    output or 5.8E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (8.1E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 0.12 lb
                                                                           per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  770 ppm by volume   8.4E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solid.                                          corrected to 3-     output or 8.4 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (520
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
                                  b. Filterable PM    1.8E-01 lb per      2.5E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 2.6 lb    run.
                                                       03 lb per MMBtu     per MWh; or (2.8E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 2.8E-02 lb per
                                                                           MWh).
12. Fuel cell units designed to   a. CO.............  1,100 ppm by        2.4 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solid.                         volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 12 lb per MWh.
                                                       to 3-percent
                                                       oxygen.
                                  b. Filterable PM    2.0E-02 lb per      5.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.8E-    output or 2.8E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (1.6E-02 lb per
                                                                           MMBtu of steam
                                                                           output or 8.1E-02
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  3,500 ppm by        3.5 lb per MMBtu    1 hr minimum
 units designed to burn biomass/                       volume on a dry     of steam output     sampling time.
 bio-based solid.                                      basis corrected     or 39 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
                                  b. Filterable PM    4.4E-01 lb per      5.5E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (4.5E-    output or 6.2 lb    run.
                                                       04 lb per MMBtu     per MWh; or (5.7E-
                                                       of heat input).     04 lb per MMBtu
                                                                           of steam output
                                                                           or 6.3E-03 lb per
                                                                           MWh).
14. Units designed to burn        a. HCl............  1.1E-03 lb per      1.4E-03 lb per      For M26A, collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.6E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  7.3E-07 \a\ lb per  8.8E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 1.1E-05   per run; for M30A
                                                                           lb per MWh.         or M30B collect a
                                                                                               minimum sample as
                                                                                               specified in the
                                                                                               method, for ASTM
                                                                                               D6784 \b\ collect
                                                                                               a minimum of 2
                                                                                               dscm.
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average.  average.

[[Page 52230]]

 
                                  b. Filterable PM    5.9E-02 lb per      7.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 8.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.8E-03
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per MWh.
                                                       percent oxygen.
                                  b. Filterable PM    7.9E-03 \a\ lb per  9.6E-03 \a\ lb per  Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (6.2E-    output or 1.1E-01   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (7.5E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           8.6E-04 lb per
                                                                           MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average   average.
                                                       based on stack
                                                       test.
                                  b. Filterable PM    2.2E-01 lb per      2.7E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (8.6E-    output or 3.1 lb    run.
                                                       04 lb per MMBtu     per MWh; or (1.1E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 1.2E-02 lb per
                                                                           MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 2 dscm.
                                  d. Filterable PM    7.3E-03 lb per      1.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input or (2.1E-04   output or 7.6E-02   run.
                                                       lb per MMBtu of     lb per MWh; or
                                                       heat input).        (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
  for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
  according to Sec.   63.7515 if all of the other provisions of Sec.   63.7515 are met. For all other pollutants
  that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years
  must show that your emissions are at or below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec.   63.14.
\c\ An owner or operator may request an alternative test method under Sec.   63.7 of this chapter, in order that
  compliance with the carbon monoxide emissions limit be determined using CO2 as a diluent correction in place
  of oxygen at 3 percent. EPA Method 19 F-factors and EPA Method 19 equations must be used to generate the
  appropriate CO2 correction percentage for the fuel type burned in the unit and must also take into account
  that the 3-percent oxygen correction is to be done on a dry basis. The alternative test method request must
  account for any CO2 being added to, or removed from, the emissions gas stream as a result of limestone
  injection, scrubber media, etc.
\d\ Before [date 3 years after date of publication of final rule in the Federal Register] you may comply with
  the emission limits in Table 15 to this subpart. On and after [date 3 years after date of publication of final
  rule in the Federal Register], you must comply with the emission limits in Table 2 to this subpart.

0
18. Table 3 of subpart DDDDD is amended by revising the entry for 
``5.'' and ``6.'' to read as follows:

      Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
     As stated in Sec.   63.7500, you must comply with the following
                   applicable work practice standards:
------------------------------------------------------------------------
    If your unit is . . .          You must meet the following . . .
------------------------------------------------------------------------
 
                              * * * * * * *
5. An existing or new boiler   a. You must operate all CMS during
 or process heater subject to   startup.
 emission limits in Table 1    b. For startup of a boiler or process
 or 2 or 11 through 13 to       heater, you must use one or a
 this subpart during startup.   combination of the following clean
                                fuels: Natural gas, synthetic natural
                                gas, propane, other Gas 1 fuels,
                                distillate oil, syngas, ultra-low sulfur
                                diesel, fuel oil-soaked rags, kerosene,
                                hydrogen, paper, cardboard, refinery
                                gas, liquefied petroleum gas, clean dry
                                biomass, and any fuels meeting the
                                appropriate HCl, mercury and TSM
                                emission standards by fuel analysis.
                               c. You have the option of complying using
                                either of the following work practice
                                standards.

[[Page 52231]]

 
                               (1) If you choose to comply using
                                definition (1) of ``startup'' in Sec.
                                63.7575, once you start firing fuels
                                that are not clean fuels you must vent
                                emissions to the main stack(s) and
                                engage all of the applicable control
                                devices except limestone injection in
                                fluidized bed combustion (FBC) boilers,
                                dry scrubber, fabric filter, and
                                selective catalytic reduction (SCR). You
                                must start your limestone injection in
                                FBC boilers, dry scrubber, fabric
                                filter, and SCR systems as expeditiously
                                as possible. Startup ends when steam or
                                heat is supplied for any purpose, OR
                               (2) If you choose to comply using
                                definition (2) of ``startup'' in Sec.
                                63.7575, once you start to feed fuels
                                that are not clean fuels, you must vent
                                emissions to the main stack(s) and
                                engage all of the applicable control
                                devices so as to comply with the
                                emission limits within 4 hours of start
                                of supplying useful thermal energy. You
                                must engage and operate PM control
                                within one hour of first feeding fuels
                                that are not clean fuels\a\. You must
                                start all applicable control devices as
                                expeditiously as possible, but, in any
                                case, when necessary to comply with
                                other standards applicable to the source
                                by a permit limit or a rule other than
                                this subpart that require operation of
                                the control devices. You must develop
                                and implement a written startup and
                                shutdown plan, as specified in Sec.
                                63.7505(e).
                               d. You must comply with all applicable
                                emission limits at all times except
                                during startup and shutdown periods at
                                which time you must meet this work
                                practice. You must collect monitoring
                                data during periods of startup, as
                                specified in Sec.   63.7535(b). You must
                                keep records during periods of startup.
                                You must provide reports concerning
                                activities and periods of startup, as
                                specified in Sec.   63.7555.
6. An existing or new boiler   You must operate all CMS during shutdown.
 or process heater subject to   While firing fuels that are not clean
 emission limits in Tables 1    fuels during shutdown, you must vent
 or 2 or 11 through 15 to       emissions to the main stack(s) and
 this subpart during shutdown.  operate all applicable control devices,
                                except limestone injection in FBC
                                boilers, dry scrubber, fabric filter,
                                and SCR but, in any case, when necessary
                                to comply with other standards
                                applicable to the source that require
                                operation of the control device.
                               If, in addition to the fuel used prior to
                                initiation of shutdown, another fuel
                                must be used to support the shutdown
                                process, that additional fuel must be
                                one or a combination of the following
                                clean fuels: Natural gas, synthetic
                                natural gas, propane, other Gas 1 fuels,
                                distillate oil, syngas, ultra-low sulfur
                                diesel, refinery gas, and liquefied
                                petroleum gas.
                               You must comply with all applicable
                                emissions limits at all times except for
                                startup or shutdown periods conforming
                                with this work practice. You must
                                collect monitoring data during periods
                                of shutdown, as specified in Sec.
                                63.7535(b). You must keep records during
                                periods of shutdown. You must provide
                                reports concerning activities and
                                periods of shutdown, as specified in
                                Sec.   63.7555.
------------------------------------------------------------------------

* * * * *
0
19. Table 4 to subpart DDDDD is amended by revising the column headings 
to read as follows:

  Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
                             Process Heaters
    As stated in Sec.   63.7500, you must comply with the applicable
                            operating limits:
------------------------------------------------------------------------
 When complying with a Table 1, 2, 11, 12,
  13, 14, or 15 numerical emission limit         You must meet these
                using . . .                    operating limits . . .
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
20. Table 7 to subpart DDDDD is amended by revising footnote ``b'' to 
read as follows:

 Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits a b
     As stated in Sec.   63.7520, you must comply with the following
             requirements for establishing operating limits:
------------------------------------------------------------------------
 
--------------------------------------------
 
                               * * * * *
------------------------------------------------------------------------
\b\ If you conduct multiple performance tests, you must set the minimum
  liquid flow rate and pressure drop operating limits at the higher of
  the minimum values established during the performance tests. For a
  minimum oxygen level, if you conduct multiple performance tests, you
  must set the minimum oxygen level at the lower of the minimum values
  established during the performance tests. For maximum operating load,
  if you conduct multiple performance tests, you must set the maximum
  operating load at the lower of the maximum values established during
  the performance tests.

0
21. Table 8 to subpart DDDDD is amended by revising the entry for 
``8.'' to read as follows:

[[Page 52232]]



Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
  As stated in Sec.   63.7540, you must show continuous compliance with
 the emission limitations for each boiler or process heater according to
                             the following:
------------------------------------------------------------------------
     If you must meet the
following operating limits or       You must demonstrate continuous
work practice standards . . .             compliance by . . .
------------------------------------------------------------------------
 
                              * * * * * * *
8. Emission limits using fuel  a. Conduct monthly fuel analysis for HCl
 analysis.                      or mercury or TSM according to Table 6
                                to this subpart; and
                               b. Reduce the data to 12-month rolling
                                averages; and
                               c. Maintain the 12-month rolling average
                                at or below the applicable emission
                                limit for HCl or mercury or TSM in
                                Tables 1 and 2 or 11 through 15 to this
                                subpart.
                               d. Calculate the HCI, mercury, and/or TSM
                                emission rate from the boiler or process
                                heater in units of lb/MMBtu using
                                Equations 7, 8, and/or 9 in Sec.
                                63.7530.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
22. Add Table 14 to subpart DDDDD of part 63 to read as follows:

 Table 14 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
                                                     Heaters
   As stated in Sec.   63.7500, you may continue to comply with the following applicable emission limits until
 [date 3 years after date of publication of final rule in the Federal Register]: [Units with heat input capacity
                                     of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                           Or the emissions
                                                      The emissions must    must not exceed
                                                        not exceed the       the following        Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  2.2E-02 lb per      2.5E-02 lb per      For M26A, collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.28 lb   dscm per run; for
                                                                           per MWh.            M26 collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  8.0E-07 \a\ lb per  8.7E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 1.1E-05   per run; for M30A
                                                                           \a\ lb per MWh.     or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 4 dscm.
2. Units designed to burn coal/   a. Filterable PM    1.1E-03 lb per      1.1E-03 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.3E-    output or 1.4E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 2.9E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. Carbon monoxide  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid       (CO) (or CEMS).     on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (320
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
4. Stokers/others designed to     a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (340
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (230
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.2E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3-     output or 1.5 lb
 fossil fuel.                                          percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (150
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  620 ppm by volume   5.8E-01 lb per      1 hr minimum
 designed to burn wet biomass                          on a dry basis      MMBtu of steam      sampling time.
 fuel.                                                 corrected to 3-     output or 6.8 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (390
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    3.0E-02 lb per      3.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.6E-    output or 4.2E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 3.7E-04
                                                                           lb per MWh).

[[Page 52233]]

 
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.2E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3-     output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.0E-02 lb per      3.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (4.0E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (4.2E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 5.6E-02
                                                                           lb per MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  230 ppm by volume   2.2E-01 lb per      1 hr minimum
 to burn biomass/bio-based                             on a dry basis      MMBtu of steam      sampling time.
 solids.                                               corrected to 3-     output or 2.6 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (310
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    9.8E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (8.3E-    output or 0.14 lb   run.
                                                       05 \a\ lb per       per MWh; or (1.1E-
                                                       MMBtu of heat       04 \a\ lb per
                                                       input).             MMBtu of steam
                                                                           output or 1.2E-03
                                                                           \a\ lb per MWh).
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based                             volume on a dry     of steam output     sampling time.
 solids.                                               basis corrected     or 27 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).
                                  b. Filterable PM    3.0E-02 lb per      3.1E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (6.5E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (6.6E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 9.1E-02
                                                                           lb per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  330 ppm by volume   3.5E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solids.                                         corrected to 3-     output or 3.6 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (520
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 10-day
                                                       rolling average).
                                  b. Filterable PM    3.2E-03 lb per      4.3E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (3.9E-    output or 4.5E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.2E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 5.5E-04
                                                                           lb per MWh).
12. Fuel cell units designed to   a. CO.............  910 ppm by volume   1.1 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solids.                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0E+01 lb per
                                                       percent oxygen.     MWh.
                                  b. Filterable PM    2.0E-02 lb per      3.0E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.9E-    output or 2.8E-01   run.
                                                       05 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (5.1E-05 lb per
                                                       input).             MMBtu of steam
                                                                           output or 4.1E-04
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  1,100 ppm by        1.4 lb per MMBtu    1 hr minimum
 boiler designed to burn biomass/                      volume on a dry     of steam output     sampling time.
 bio-based solids.                                     basis corrected     or 12 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\d\ 30-day
                                                       rolling average).
                                  b. Filterable PM    2.6E-02 lb per      3.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (4.4E-    output or 3.7E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 6.2E-03
                                                                           lb per MWh).
14. Units designed to burn        a. HCl............  4.4E-04 lb per      4.8E-04 lb per      For M26A: Collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 6.1E-03   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  4.8E-07 \a\ lb per  5.3E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 6.7E-06   per run; for M30A
                                                                           \a\ lb per MWh.     or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 4 dscm.
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average.  average.
                                  b. Filterable PM    1.3E-02 lb per      1.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (7.5E-    output or 1.8E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (8.2E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 1.1E-03
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per MWh.
                                                       percent oxygen.

[[Page 52234]]

 
                                  b. Filterable PM    1.1E-03 \a\ lb per  1.2E-03 \a\ lb per  Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.9E-    output or 1.6E-02   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (3.2E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           4.0E-04 lb per
                                                                           MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average   average.
                                                       based on stack
                                                       test.
                                  b. Filterable PM    2.3E-02 lb per      2.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 4 dscm per
                                                       input; or (8.6E-    output or 3.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (9.4E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 1.2E-02
                                                                           lb per MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, Collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 3 dscm.
                                  d. Filterable PM    6.7E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.1E-    output or 7.0E-02   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           lb per MWh).
----------------------------------------------------------------------------------------------------------------

0
23. Add Table 15 to subpart DDDDD of part 63 to read as follows:

   Table 15 to Subpart DDDDD of Part 63--Alternative Emission Limits for Existing Boilers and Process Heaters
As stated in Sec.   63.7500, you may continue to comply with following emission limits until [date 3 years after
  date of publication of final rule in the Federal Register]: [Units with heat input capacity of 10 million Btu
                                              per hour or greater]
----------------------------------------------------------------------------------------------------------------
                                                                          The emissions must
                                                      The emissions must    not exceed the
                                                        not exceed the         following          Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this  subcategory . . .    pollutants . . .     limits, except       based limits,       volume or test
                                                      during startup and     except during    run duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  2.2E-02 lb per      2.5E-02 lb per      For M26A, Collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.27 lb   dscm per run; for
                                                                           per MWh.            M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  5.7E-06 lb per      6.4E-06 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 7.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 3 dscm.
2. Units design to burn coal/     a. Filterable PM    4.0E-02 lb per      4.2E-02 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.3E-    output or 4.9E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.6E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 6.5E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. CO (or CEMS)...  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid                           on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (320
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
4. Stokers/others designed to     a. CO (or CEMS)...  160 ppm by volume   0.14 lb per MMBtu   1 hr minimum
 burn coal/solid fossil fuel.                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.7 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (340
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).

[[Page 52235]]

 
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run           average.
                                                       average; or (230
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.3E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3-     output or 1.5 lb
 fossil fuel.                                          percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (150
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  1,500 ppm by        1.4 lb per MMBtu    1 hr minimum
 designed to burn wet biomass                          volume on a dry     of steam output     sampling time.
 fuel.                                                 basis corrected     or 17 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or (720
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
                                  b. Filterable PM    3.7E-02 lb per      4.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.4E-    output or 5.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.8E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 3.4E-04
                                                                           lb per MWh).
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.2E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3-     output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.2E-01 lb per      3.7E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (4.0E-    output or 4.5 lb    run.
                                                       03 lb per MMBtu     per MWh; or (4.6E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 5.6E-02 lb per
                                                                           MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  470 ppm by volume   4.6E-01 lb per      1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      MMBtu of steam      sampling time.
                                                       corrected to 3-     output or 5.2 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (310
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).
                                  b. Filterable PM    1.1E-01 lb per      1.4E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (1.2E-    output or 1.6 lb    run.
                                                       03 lb per MMBtu     per MWh; or (1.5E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 1.7E-02 lb per
                                                                           MWh).
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based solid.                      volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 27 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3-percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
                                  b. Filterable PM    5.1E-02 lb per      5.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (6.5E-    output or 7.1E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (6.6E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 9.1E-02
                                                                           lb per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  770 ppm by volume   8.4E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solid.                                          corrected to 3-     output or 8.4 lb
                                                       percent oxygen,     per MWh; three-
                                                       three-run           run average.
                                                       average; or (520
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 10-day
                                                       rolling average).
                                  b. Filterable PM    2.8E-01 lb per      3.9E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 3.9 lb    run.
                                                       03 lb per MMBtu     per MWh; or (2.8E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 2.8E-02 lb per
                                                                           MWh).
12. Fuel cell units designed to   a. CO.............  1,100 ppm by        2.4 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solid.                         volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 12 lb per MWh.
                                                       to 3-percent
                                                       oxygen.
                                  b. Filterable PM    2.0E-02 lb per      5.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.8E-    output or 2.8E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (1.6E-02 lb per
                                                                           MMBtu of steam
                                                                           output or 8.1E-02
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  3,500 ppm by        3.5 lb per MMBtu    1 hr minimum
 units designed to burn biomass/                       volume on a dry     of steam output     sampling time.
 bio-based solid.                                      basis corrected     or 39 lb per MWh;
                                                       to 3-percent        three-run average.
                                                       oxygen, three-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3-
                                                       percent
                                                       oxygen,\c\ 30-day
                                                       rolling average).

[[Page 52236]]

 
                                  b. Filterable PM    4.4E-01 lb per      5.5E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (4.5E-    output or 6.2 lb    run.
                                                       04 lb per MMBtu     per MWh; or (5.7E-
                                                       of heat input).     04 lb per MMBtu
                                                                           of steam output
                                                                           or 6.3E-03 lb per
                                                                           MWh).
14. Units designed to burn        a. HCl............  1.1E-03 lb per      1.4E-03 lb per      For M26A, collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.6E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  2.0E-06 \a\ lb per  2.5E-06 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 2.8E-05   per run; for M30A
                                                                           lb per MWh.         or M30B collect a
                                                                                               minimum sample as
                                                                                               specified in the
                                                                                               method, for ASTM
                                                                                               D6784 \b\ collect
                                                                                               a minimum of 2
                                                                                               dscm.
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three-run average.  average.
                                  b. Filterable PM    6.2E-02 lb per      7.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 8.6E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.8E-03
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.4 lb per MWh.
                                                       percent oxygen.
                                  b. Filterable PM    7.9E-03 \a\ lb per  9.6E-03 \a\ lb per  Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (6.2E-    output or 1.1E-01   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (7.5E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           8.6E-04 lb per
                                                                           MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3-     or 1.4 lb per
                                                       percent oxygen,     MWh; three-run
                                                       three3-run          average.
                                                       average based on
                                                       stack test.
                                  b. Filterable PM    2.7E-01 lb per      3.3E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (8.6E-    output or 3.8 lb    run.
                                                       04 lb per MMBtu     per MWh; or (1.1E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 1.2E-02 lb per
                                                                           MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3-     or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 2 dscm.
                                  d. Filterable PM    6.7E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of three dscm per
                                                       input or (2.1E-04   output or 7.0E-02   run.
                                                       lb per MMBtu of     lb per MWh; or
                                                       heat input).        (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           lb per MWh).
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2020-15121 Filed 8-21-20; 8:45 am]
BILLING CODE 6560-50-P

This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.