Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule, 31802-31959 [2024-07413]

Download as PDF 31802 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 9 and 98 [EPA–HQ–OAR–2019–0424; FRL–7230–01– OAR] RIN 2060–AU35 Revisions and Confidentiality Determinations for Data Elements Under the Greenhouse Gas Reporting Rule Environmental Protection Agency (EPA). ACTION: Final rule. AGENCY: The EPA is amending specific provisions in the Greenhouse Gas Reporting Rule to improve data quality and consistency. This action updates the General Provisions to reflect revised global warming potentials; expands reporting to additional sectors; improves the calculation, recordkeeping, and reporting requirements by updating existing methodologies; improves data verifications; and provides for collection of additional data to better inform and be relevant to a wide variety of Clean Air Act provisions that the EPA carries out. This action adds greenhouse gas monitoring and reporting for five source categories including coke calcining; ceramics manufacturing; calcium carbide production; caprolactam, glyoxal, and glyoxylic acid production; and facilities conducting geologic sequestration of carbon dioxide with enhanced oil recovery. These revisions also include changes that will improve implementation of the rule such as SUMMARY: updates to applicability estimation methodologies, simplifying calculation and monitoring methodologies, streamlining recordkeeping and reporting, and other minor technical corrections or clarifications. This action also establishes and amends confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these amendments. DATES: This rule is effective January 1, 2025. The incorporation by reference of certain material listed in this final rule is approved by the Director of the Federal Register beginning January 1, 2025. The incorporation by reference of certain other material listed in the rule was approved by the Director of the Federal Register as of January 1, 2018. ADDRESSES: The EPA has established a docket for this action under Docket ID No. EPA–HQ–OAR–2019–0424. All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW, Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566–1744 and the telephone number for the Air Docket is (202) 566–1742. FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change Division, Office of Atmospheric Programs (MC–6207A), Environmental Protection Agency, 1200 Pennsylvania Ave., NW, Washington, DC 20460; telephone number: (202) 343–9548; email address: GHGReporting@epa.gov. For technical information, please go to the Greenhouse Gas Reporting Program (GHGRP) website, www.epa.gov/ ghgreporting. To submit a question, select Help Center, followed by ‘‘Contact Us.’’ World Wide Web (WWW). In addition to being available in the docket, an electronic copy of this final rule will also be available through the WWW. Following the Administrator’s signature, a copy of this final rule will be posted on the EPA’s GHGRP website at www.epa.gov/ghgreporting. SUPPLEMENTARY INFORMATION: Regulated entities. These final revisions affect certain entities that must submit annual greenhouse gas (GHG) reports under the GHGRP (codified at 40 CFR part 98). These are amendments to existing regulations and will affect owners or operators of certain industry sectors that are suppliers and direct emitters of GHGs. Regulated categories and entities include, but are not limited to, those listed in table 1 of this preamble: TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY North American Industry Classification System (NAICS) Category lotter on DSK11XQN23PROD with RULES2 General Stationary Fuel Combustion Sources ........................ .............................. 211 Electric Power Generation ....................................................... Adipic Acid Production ............................................................. 321 322 325 324 316, 326, 339 331 332 336 221 622 611 2211 325199 Aluminum Production ............................................................... Ammonia Manufacturing .......................................................... Calcium Carbide Production .................................................... 331313 325311 325180 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 Examples of facilities that may be subject to part 98:+ Facilities operating boilers, process heaters, incinerators, turbines, and internal combustion engines. 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. Generation facilities that produce electric energy. All other basic organic chemical manufacturing: Adipic acid manufacturing. Primary aluminum production facilities. Anhydrous ammonia manufacturing facilities. Other basic inorganic chemical manufacturing: calcium carbide manufacturing. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31803 TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued North American Industry Classification System (NAICS) Category Carbon Dioxide Enhanced Oil Recovery Projects .................. 211120 Caprolactam, Glyoxal, and Glyoxylic Acid Production ............ Cement Production .................................................................. Ceramics Manufacturing .......................................................... 325199 327310 327110 327120 299901 334111 334413 Coke Calcining ......................................................................... Electronics Manufacturing ....................................................... 334419 Electrical Equipment Manufacture or Refurbishment .............. 33531 Electricity generation units that report through 40 CFR part 75. Electrical Equipment Use ........................................................ Electrical transmission and distribution equipment manufacture or refurbishment. Ferroalloy Production ............................................................... Fluorinated Greenhouse Gas Production ................................ Geologic Sequestration ........................................................... Glass Production ..................................................................... 221112 HCFC–22 Production ............................................................... 325120 HFC–23 destruction processes that are not collocated with a HCFC–22 production facility and that destroy more than 2.14 metric tons of HFC–23 per year. Hydrogen Production ............................................................... Industrial Waste Landfill .......................................................... Industrial Wastewater Treatment ............................................. Injection of Carbon Dioxide ..................................................... Iron and Steel Production ........................................................ 325120 Lead Production ....................................................................... Lime Manufacturing ................................................................. Magnesium Production ............................................................ 331 327410 331410 Nitric Acid Production .............................................................. 325311 Petroleum and Natural Gas Systems ...................................... 486210 221210 211120 211130 324110 324110 325312 322110 322120 322130 221121 33361 331110 325120 NA 327211 327213 327212 325120 562212 221310 211 333110 lotter on DSK11XQN23PROD with RULES2 Petrochemical Production ........................................................ Petroleum Refineries ............................................................... Phosphoric Acid Production .................................................... Pulp and Paper Manufacturing ................................................ Examples of facilities that may be subject to part 98:+ Oil and gas extraction projects using carbon dioxide enhanced oil recovery. All other basic organic chemical manufacturing. Cement manufacturing. Pottery, ceramics, and plumbing fixture manufacturing. Clay building material and refractories manufacturing. Coke; coke, petroleum; coke, calcined petroleum. Microcomputers manufacturing facilities. Semiconductor, photovoltaic (PV) (solid-state) device manufacturing facilities. Liquid crystal display (LCD) unit screens manufacturing facilities; Microelectromechanical (MEMS) manufacturing facilities. Power transmission and distribution switchgear and specialty transformers manufacturing facilities. Electric power generation, fossil fuel (e.g., coal, oil, gas). Electric bulk power transmission and control facilities. Engine, Turbine, and Power Transmission Equipment Manufacturing. Ferroalloys manufacturing. Industrial gases manufacturing facilities. CO2 geologic sequestration sites. Flat glass manufacturing facilities. Glass container manufacturing facilities. Other pressed and blown glass and glassware manufacturing facilities. Industrial gas manufacturing: Hydrochlorofluorocarbon (HCFC) gases manufacturing. Industrial gas manufacturing: Hydrofluorocarbon (HFC) gases manufacturing. Hydrogen manufacturing facilities. Solid waste landfills. Water treatment plants. Oil and gas extraction. Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, basic oxygen process furnace (BOPF) shops. Primary metal manufacturing. Lime production. Nonferrous metal (except aluminum) smelting and refining: Magnesium refining, primary. Nitrogenous fertilizer manufacturing: Nitric acid manufacturing. Pipeline transportation of natural gas. Natural gas distribution facilities. Crude petroleum extraction. Natural gas extraction. Petrochemicals made in petroleum refineries. Petroleum refineries. Phosphatic fertilizer manufacturing. Pulp mills. Paper mills. Paperboard mills. Miscellaneous Uses of Carbonate ........................................... Facilities included elsewhere. Municipal Solid Waste Landfills ............................................... Silicon Carbide Production ...................................................... Soda Ash Production ............................................................... 562212 221320 327910 325180 Suppliers of Carbon Dioxide .................................................... Suppliers of Industrial Greenhouse Gases ............................. Titanium Dioxide Production .................................................... 325120 325120 325180 Underground Coal Mines ......................................................... 212115 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 Solid waste landfills. Sewage treatment facilities. Silicon carbide abrasives manufacturing. Other basic inorganic chemical manufacturing: Soda ash manufacturing. Industrial gas manufacturing facilities. Industrial greenhouse gas manufacturing facilities. Other basic inorganic chemical manufacturing: Titanium dioxide manufacturing. Underground coal mining. E:\FR\FM\25APR2.SGM 25APR2 31804 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued North American Industry Classification System (NAICS) Category Zinc Production ........................................................................ 331410 Suppliers of Coal-based Liquid Fuels ..................................... Suppliers of Natural Gas and Natural Gas Liquids ................. 211130 221210 211112 324110 325120 325120 423730 333415 Suppliers of Petroleum Products ............................................. Suppliers of Carbon Dioxide .................................................... Suppliers of Industrial Greenhouse Gases ............................. Importers and Exporters of Pre-charged Equipment and Closed-Cell Foams. 423620 449210 326150 335313 423610 lotter on DSK11XQN23PROD with RULES2 Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be affected by this action. This table lists the types of facilities that the EPA is now aware could potentially be affected by this action. Other types of facilities than those listed in the table could also be subject to reporting requirements. To determine whether you will be affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A (General Provisions) and each source category. Many facilities that are affected by 40 CFR part 98 have greenhouse gas emissions from multiple source categories listed in table 1 of this preamble. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. Acronyms and abbreviations. The following acronyms and abbreviations are used in this document. ACE Automated Commercial Environment AIM American Innovation and Manufacturing Act of 2020 ANSI American National Standards Institute API American Petroleum Institute ASME American Society of Mechanical Engineers ASTM ASTM, International BAMM best available monitoring methods BCFCs bromochlorofluorocarbons BEF byproduct emission factor BFCs bromofluorocarbons CAA Clean Air Act CaO calcium oxide (lime) CARB California Air Resources Board CAS Chemical Abstracts Service VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Examples of facilities that may be subject to part 98:+ Nonferrous metal (except aluminum) smelting and refining: Zinc refining, primary. Coal liquefaction at mine sites. Natural gas distribution facilities. Natural gas liquid extraction facilities. Petroleum refineries. Industrial gas manufacturing facilities. Industrial greenhouse gas manufacturing facilities. Air-conditioning equipment (except room units) merchant wholesalers. Air-conditioning equipment (except motor vehicle) manufacturing. Air-conditioners, room, merchant wholesalers. Electronics and appliance retailers. Polyurethane foam products manufacturing. Circuit breakers, power, manufacturing. Circuit breakers and related equipment merchant wholesalers. CBI confidential business information CBP U.S. Customs and Border Protection CCS carbon capture and sequestration CECS combustion emissions control system CEMS continuous emissions monitoring system CFC chlorofluorocarbon CFR Code of Federal Regulations CF4 perfluoromethane CGA cylinder gas audit CHP combined heat and power CH4 methane CKD cement kiln dust CO2 carbon dioxide CO2e carbon dioxide equivalent COF2 carbonic difluoride CRA Congressional Review Act CSA CSA Group DAC direct air capture DCU delayed coking unit DOC degradable organic carbon DOE U.S. Department of Energy DRE destruction or removal efficiency EAF electric arc furnace EDC ethylene dichloride EF emission factor EGU electricity generating unit e-GGRT electronic Greenhouse Gas Reporting Tool EG emission guidelines EOR enhanced oil recovery EPA U.S. Environmental Protection Agency EREF Environmental Research and Education Foundation F–GHG fluorinated greenhouse gas F–HTF fluorinated heat transfer fluids FLIGHT Facility Level Information on Greenhouse Gases Tool FR Federal Register FTIR Fourier Transform Infrared GCCS gas collection and capture system GHG greenhouse gas GHGRP Greenhouse Gas Reporting Program GIE gas-insulated equipment GWP global warming potential HBCFC hydrobromochlorofluorocarbon HBFC hydrobromofluorocarbon HC hydrocarbon PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 HCFC hydrochlorofluorocarbon HCFE hydrochlorofluoroether HFC hydrofluorocarbon HFE hydrofluoroether HHV high heating value HTF heat transfer fluid HTS Harmonized Tariff System ICR Information Collection Request IPCC Intergovernmental Panel on Climate Change ISO International Standards Organization IVT Inputs Verification Tool k first order decay rate kg kilogram kV kilovolt LCD liquid crystal display LDC local distribution company LMOP Landfill Methane Outreach Program MEMS Microelectromechanical systems MgO magnesium oxide mmBtu million British thermal units MRV monitoring, reporting, and verification plan MW molecular weight MSW municipal solid waste mt metric tons mtCO2e metric tons carbon dioxide equivalent MTBS Mean Time Between Service NAICS North American Industry Classification System NIST National Institute of Standards and Technology NSPS new source performance standards N2O nitrous oxide OAR Office of Air and Radiation OMB Office of Management and Budget OMP operations management plan PFC perfluorocarbon POU point of use POX partial oxidation ppmv parts per million volume PRA Paperwork Reduction Act PSA pressure swing absorption psi pounds per square inch psia pounds per square inch, absolute PV photovoltaic QA/QC quality assurance/quality control E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations RFA Regulatory Flexibility Act RPC remote plasma cleaning RY reporting year scf standard cubic feet SEM surface-emissions monitoring SF6 sulfur hexafluoride SMR steam methane reforming SSM startup, shutdown, and malfunction TSD technical support document UMRA Unfunded Mandates Reform Act of 1995 UNFCCC United Nations Framework Convention on Climate Change U.S. United States VCM vinyl chloride monomer WGS water gas shift WMO World Meteorological Organization WWW World Wide Web lotter on DSK11XQN23PROD with RULES2 Table of Contents I. Background A. How is this preamble organized? B. Executive Summary C. Background on This Final Rule D. Legal Authority II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9 III. Final Revisions to Each Subpart of Part 98 and Summary of Comments and Responses A. Subpart A—General Provisions B. Subpart B—Energy Consumption C. Subpart C—General Stationary Fuel Combustion D. Subpart F—Aluminum Production E. Subpart G—Ammonia Manufacturing F. Subpart H—Cement Production G. Subpart I—Electronics Manufacturing H. Subpart N—Glass Production I. Subpart P—Hydrogen Production J. Subpart Q—Iron and Steel Production K. Subpart S—Lime Production L. Subpart U—Miscellaneous Uses of Carbonate M. Subpart X—Petrochemical Production N. Subpart Y—Petroleum Refineries O. Subpart AA—Pulp and Paper Manufacturing P. Subpart BB—Silicon Carbide Production Q. Subpart DD—Electrical Transmission and Distribution Equipment Use R. Subpart FF—Underground Coal Mines S. Subpart GG—Zinc Production T. Subpart HH—Municipal Solid Waste Landfills U. Subpart OO—Suppliers of Industrial Greenhouse Gases V. Subpart PP—Suppliers of Carbon Dioxide W. Subpart QQ—Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment and Closed-Cell Foams X. Subpart RR—Geologic Sequestration of Carbon Dioxide Y. Subpart SS—Electrical Equipment Manufacture or Refurbishment Z. Subpart UU—Injection of Carbon Dioxide AA. Subpart VV—Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916 BB. Subpart WW—Coke Calciners CC. Subpart XX—Calcium Carbide Production DD. Subpart YY—Caprolactam, Glyoxal, and Glyoxylic Acid Production VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 EE. Subpart ZZ—Ceramics Manufacturing IV. Final Revisions to 40 CFR Part 9 V. Effective Date of the Final Amendments VI. Final Confidentiality Determinations A. EPA’s Approach to Assessing Data Elements B. Final Confidentiality Determinations and Emissions Data Designations C. Final Reporting Determinations for Inputs to Emission Equations VII. Impacts and Benefits of the Final Amendments VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 14094: Modernizing Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act and 1 CFR Part 51 J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act L. Judicial Review I. Background A. How is this preamble organized? Section I. of this preamble contains background information on the June 21, 2022 proposed rule (87 FR 36920, hereafter referred to as ‘‘2022 Data Quality Improvements Proposal’’) and the May 22, 2023 supplemental proposed rule (88 FR 32852, hereafter referred to as ‘‘2023 Supplemental Proposal’’). This section also discusses the EPA’s legal authority under the CAA to promulgate (including subsequent amendments to) the GHG Reporting Rule, codified at 40 CFR part 98 (hereinafter referred to as ‘‘part 98’’), and the EPA’s legal authority to make confidentiality determinations for new or revised data elements corresponding to these amendments or for existing data elements for which the EPA is finalizing a new determination. Section II. of this preamble describes the types of amendments included in this final rule. Section III. of this preamble is organized by part 98 subpart and contains detailed information on the final new requirements for, or revisions to, each subpart. Section IV. of this preamble describes the final revisions to 40 CFR part 9. Section V. of this preamble explains the effective date of the final PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 31805 revisions and how the revisions are required to be implemented in reporting year (RY) 2024 and RY2025 reports. Section VI. of this preamble discusses the final confidentiality determinations for new or substantially revised (i.e., requiring additional or different data to be reported) data reporting elements, as well as for certain existing data elements for which the EPA is finalizing a new determination. Section VII. of this preamble discusses the impacts of the final amendments. Finally, section VIII. of this preamble describes the statutory and Executive order requirements applicable to this action. B. Executive Summary The EPA is finalizing certain proposed revisions to part 98 included in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, with some changes made after consideration of public comments. The final amendments include improvements to requirements that, broadly, will enhance the quality and the scope of information collected, clarify elements of the rule, and streamline elements of reporting and recordkeeping. These final revisions include a comprehensive update to the global warming potentials (GWPs) in table A–1 to subpart A of part 98; updates to provide for collection of additional data to understand new source categories or new emission sources for specific sectors; updates to emission factors to more accurately reflect industry emissions; refinements to existing emissions calculation methodologies to reflect an improved understanding of emissions sources and end uses of GHGs; additions or modifications to reporting requirements in order to eliminate data gaps and improve verification of reported emissions; revisions that address prior commenter concerns or clarify requirements; and editorial corrections that are intended to improve the public’s understanding of the rule. The final amendments also include streamlining measures such as revisions to applicability for certain industry sectors to account for changes in usage of certain GHGs or instances where the current applicability estimation methodology may overestimate emissions; revisions that provide flexibility for or simplify monitoring and calculation methods; and revisions to streamline reported data elements or recordkeeping where the current requirements are redundant, where reported data are not currently useful for verification or analysis, or for which continued collection of the data at the same frequency would not likely E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31806 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations provide new insights or knowledge of the industry sector, emissions, or trends at this time. This action also finalizes confidentiality determinations for the reporting of data elements added or substantially revised in these final amendments, and for certain existing data elements for which no confidentiality determination has been made previously or for which the EPA proposed to revise the existing determination. In some cases, and as further described in section III. of this preamble, the EPA is not taking final action in this final rule on certain proposed revisions included in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. For example, after review of comments received in response to the proposed requirements to report purchased electricity and thermal energy consumption information under the proposed subpart B (Energy Consumption), the EPA is not taking action at this time on those proposed provisions. The EPA believes additional time is needed to consider the comments received before taking final action. Similarly, the EPA is not taking final action at this time on certain proposed changes for some subparts. In some cases, e.g., for subparts G (Ammonia Production), P (Hydrogen Production), S (Lime Production), and HH (Municipal Solid Waste Landfills), we are not taking final action at this time on certain revisions to the calculation or monitoring methodologies that would have revised how data are collected and reported in the EPA’s electronic greenhouse gas reporting tool (e-GGRT). In several cases, we are also not taking final action at this time on proposed revisions to add reporting requirements. For example, under subpart C (General Stationary Fuel Combustion), we are not taking final action at this time on proposed revisions to the requirements for units in either an aggregation of units or common pipe configuration that would have required reporters to provide additional information such as the unit type, maximum rated heat input capacity, and fraction of the actual total heat input for each unit in the aggregation or the common pipe configuration. Also under subpart C, we are not taking final action at this time on proposed requirements that would have required reporters to identify, for any configuration, whether the unit is an electricity generating unit, and, for group configurations (i.e., common stack/duct, common pipe, and aggregation of units) that contain an VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 electricity generating unit, the estimated decimal fraction of total emissions attributable to the electricity generating unit. Similarly, we are not taking final action at this time on certain data elements that were proposed to be added to subparts A (General Provisions), F (Aluminum Production), G, H (Cement Production), P, S, HH, OO (Suppliers of Industrial Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment and Closed-Cell Foams). Additional proposed revisions that EPA is not taking final action on at this time are discussed in section III. of this preamble. This final rule also includes an amendment to 40 CFR part 9 to include the Office of Management and Budget (OMB) control number issued under the Paperwork Reduction Act (PRA) for the information collection request for the GHGRP. The final amendments will become effective on January 1, 2025. As provided under the existing regulations in subpart A of part 98, the GWP amendments to table A–1 to subpart A will apply to reports submitted by current reporters that are submitted in calendar year 2025 and subsequent years (i.e., starting with reports submitted for RY2024 on March 31, 2025). All other final revisions, which apply to both existing and new reporters, will be implemented for reports prepared for RY2025 and submitted March 31, 2026. Reporters who are newly subject to the rule will be required to implement all requirements to collect data, including any required monitoring and recordkeeping, on January 1, 2025. These final amendments are anticipated to result in an overall increase in burden for part 98 reporters in cases where the amendments expand current applicability, add or revise reporting requirements, or require additional emissions data to be reported. The primary burden associated with the final rule is due to revisions to applicability, including revisions to the global warming potentials in table A–1 to subpart A of part 98, that will change the number of reporters currently at or near the 25,000 metric tons carbon dioxide equivalent (mtCO2e) threshold; revisions to establish requirements for new source categories for coke calcining, calcium carbide, caprolactam, glyoxal, and glyoxylic acid production, ceramics manufacturing, and facilities conducting geologic sequestration of carbon dioxide with enhanced oil recovery; and revisions to expand reporting to include PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 new emission sources for specific sectors, such as the addition of captive (non-merchant) hydrogen production facilities. The final revisions will affect approximately 254 new reporters across 13 source categories, including the hydrogen production, petroleum and natural gas systems, petroleum refineries, electrical transmission and distribution systems, industrial wastewater treatment, municipal solid waste landfills, fluorinated GHG suppliers, and industrial waste landfills source categories, as well as the new source categories added in these final revisions. The EPA anticipates some decrease in burden where the final revisions will adjust or improve the estimation methodologies for determining applicability, simplify calculation methodologies or monitoring requirements, or simplify the data that must be reported. In several cases, we are also finalizing changes where we anticipate increased clarity or more flexibility for reporters that could result in a potential decrease in burden. The incremental implementation labor costs for all subparts include $2,684,681 in RY2025, and $2,671,831 in each subsequent year (RY2026 and RY2027). The incremental implementation labor costs over the next three years (RY2025 through RY2027) total $8,028,343. There is an additional incremental burden of $2,733,937 for capital and operation and maintenance (O&M) costs in RY2025 and in each subsequent year (RY2026 and RY2027), which reflects changes to applicability and monitoring for subparts with new or additional reporters. The incremental non-labor costs for RY2025 through RY2027 total $8,201,812 over the next three years. C. Background on This Final Rule The GHGRP requires annual reporting of GHG data and other relevant information from large facilities and suppliers in the United States. In its 2022 Data Quality Improvements Proposal, the EPA proposed amendments to specific provisions of part 98 where we identified opportunities to improve the quality of the data collected under the rule. This included revisions that would provide for the collection of additional data that may be necessary to better understand emissions from specific sectors or inform future policy decisions under the CAA; update emission factors; and refine emissions estimation methodologies. The proposed rule also included revisions that provided for the collection of additional data that would be useful to improve verification of collected data and complement or E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations inform other EPA programs. These proposed revisions included the incorporation of a new source category to add calculation and reporting requirements for quantifying geologic sequestration of CO2 in association with enhanced oil recovery (EOR) operations. In several cases, the 2022 Data Quality Improvements Proposal included revisions that would resolve gaps in the current coverage of the GHGRP that leave out potentially significant sources of GHG emissions or end uses. The EPA also proposed revisions that clarified or updated provisions that may be unclear, and that would streamline calculation, monitoring, or reporting in specific provisions in part 98 to provide flexibility or increase the efficiency of data collection. The EPA included a request for comment on expanding the GHGRP to include several new source categories (see section IV. of the preamble to the 2022 Data Quality Improvements Proposal at 87 FR 37016) and requested comment on potential future amendments to add new calculation, monitoring, and reporting requirements for these categories. The EPA also proposed confidentiality determinations for new or substantially revised data reporting elements that would be amended under the proposed rule, as well as for certain existing data elements for which the EPA proposed a new or revised determination. The EPA received comments on the 2022 Data Quality Improvements Proposal from June 21, 2022, through October 6, 2022. The EPA subsequently proposed additional amendments to part 98 where the Agency had received or identified new information to further improve the data collected under the GHGRP. The 2023 Supplemental Proposal included amendments that were informed by a review of comments and information provided by stakeholders on the 2022 Data Quality Improvements Proposal, as well as newly proposed amendments that the EPA had identified from program implementation, e.g., where additional data would improve verification of data reported to the GHGRP or would further aid our understanding of changing industry emission trends. The 2023 Supplemental Proposal included a proposed comprehensive update to the GWPs in table A–1 to subpart A of part 98; proposed amendments to establish new subparts with specific reporting provisions under part 98 for five new source categories; and several proposed revisions where the EPA had identified new data supporting improvements to the calculation, monitoring, and recordkeeping requirements. The 2023 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Supplemental Proposal also clarified or corrected specific proposed provisions of the 2022 Data Quality Improvements Proposal. The amendments included in the 2023 Supplemental Proposal were proposed as part of the EPA’s continued efforts to address potential data gaps and improve the quality of the data collected in the GHGRP. The EPA also proposed confidentiality determinations for new or substantially revised data reporting elements that would be revised under the supplemental proposed amendments. The EPA received comments on the 2023 Supplemental Proposal from May 22, 2023, through July 21, 2023. The revisions included in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal were based on the EPA’s assessment of advances in scientific understanding of GHG emissions sources, updated guidance on GHG estimation methods, and a review of the data collected and emissions trends established following more than 10 years of implementation of the program. The EPA is finalizing amendments and confidentiality determinations in this action, with certain changes from the proposed rules following consideration of comments submitted and based on the EPA’s updated assessment. The revisions reflect the EPA’s efforts to update and improve the GHGRP by better capturing the changing landscape of GHG emissions, providing for more complete coverage of U.S. GHG emission sources, and providing a more comprehensive approach to understanding GHG emissions. Responses to major comments submitted on the proposed amendments from the 2022 Data Quality Improvement Proposal and the 2023 Supplemental Proposal considered in the development of this final rule can be found in sections III. and VI. of this preamble. Documentation of all comments received as well as the EPA’s responses can be found in the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424. This final rule does not address implementation of provisions of the Inflation Reduction Act, which was signed into law on August 16, 2022. Section 60113 of the Inflation Reduction Act amended the CAA by adding section 136, ‘‘Methane Emissions and Waste Reduction Incentive Program for Petroleum and Natural Gas Systems.’’ Although the EPA proposed amendments to subpart W of part 98 PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 31807 (Petroleum and Natural Gas Systems) in the 2022 Data Quality Improvements Proposal, these were developed prior to the Congressional direction provided in CAA section 136. The EPA noted in the preamble to the 2023 Supplemental Proposal (see section I.B., 88 FR 32855) that we intend to issue one or more separate actions to implement the requirements of CAA section 136, including revisions to certain requirements of subpart W. Subsequently, the EPA published a proposed rule for subpart W on August 1, 2023 (88 FR 50282, hereinafter referred to as the ‘‘2023 Subpart W Proposal’’), as well as a proposed rule to implement CAA section 136(c), ‘‘Waste Emissions Charge,’’ that was signed by the Administrator on January 12, 2024 and published on January 26, 2024 (89 FR 5318),1 to comply with CAA section 136. As discussed in the 2023 Subpart W Proposal, the EPA considered the 2022 Data Quality Improvements Proposal as well as additional proposed revisions in the development of the 2023 Subpart W Proposal. Accordingly, the EPA is not taking final action on the revisions to subpart W, including harmonizing revisions to subparts A (General Provisions) and C (General Stationary Fuel Combustion Sources) related to subpart W, that were proposed in the 2022 Data Quality Improvements Proposal in this final rule. D. Legal Authority The EPA is finalizing these rule amendments under its existing CAA authority provided in CAA section 114. As stated in the preamble to the Mandatory Reporting of Greenhouse Gases final rule (74 FR 56260, October 30, 2009), CAA section 114(a)(1) provides the EPA authority to require the information gathered by this rule because such data will inform and are relevant to the EPA’s carrying out of a variety of CAA provisions. Thus, when promulgating amendments to the GHGRP, the EPA has assessed the reasonableness of requiring the information to be provided and explained how the data are relevant to the EPA’s ability to carry out the provisions of the CAA. See the preambles to the proposed GHG 1 CAA section 136(c), ‘‘Waste Emissions Charge,’’ directs the Administrator to impose and collect a charge on methane (CH4) emissions that exceed statutorily specified waste emissions thresholds from an owner or operator of an applicable facility that reports more than 25,000 metric tons carbon dioxide equivalent pursuant to the Greenhouse Gas Reporting Rule’s requirements for the petroleum and natural gas systems source category (codified as subpart W in EPA’s Greenhouse Gas Reporting Rule regulations). E:\FR\FM\25APR2.SGM 25APR2 31808 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 Reporting Rule (74 FR 16448, April 10, 2009) and the final GHG Reporting Rule (74 FR 56260, October 30, 2009) for further discussion of this authority. Additionally, in enacting CAA section 136 (discussed above in preamble section I.C.), Congress implicitly recognized EPA’s appropriate use of CAA authority in promulgating the GHGRP. The provisions of CAA section 136 reference and are in part based on the Greenhouse Gas Reporting Rule requirements under subpart W for the petroleum and natural gas systems source category and require further revisions to subpart W for purposes of supporting implementation of section 136. The Administrator has determined that this action is subject to the provisions of section 307(d) of the CAA (see also section VIII.L. of this preamble). Section 307(d) contains a set of procedures relating to the issuance and review of certain CAA rules. In addition, pursuant to sections 114, 301, and 307 of the CAA, the EPA is publishing final confidentiality determinations for the new or substantially revised data elements required by these amendments. Section 114(c) requires that the EPA make information obtained under section 114 available to the public, except for information (excluding emission data) that qualifies for confidential treatment. II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9 Relevant to this final rule, the EPA previously proposed revisions to part 98 in two separate documents: the 2022 Data Quality Improvements Proposal (June 21, 2022, 87 FR 36920) and the 2023 Supplemental Proposal (May 22, 2023, 88 FR 32852). In the proposed rules, the EPA identified two primary categories of revisions that we are finalizing in this rule. First, the EPA identified revisions that would modify the rule to improve the quality of the data collected and better inform the EPA’s understanding of U.S. GHG emissions sources. Specifically, the EPA identified six types of revisions to improve the quality of the data collected under part 98 that we are finalizing in this rule, as follows: • Revisions to table A–1 to the General Provisions of part 98 to update GWPs to reflect advances in scientific knowledge and better characterize the climate impacts of certain GHGs, by including values agreed to under the United Nations Framework Convention on Climate Change, and to maintain comparability and consistency with the Inventory of U.S. Greenhouse Gas Emissions and Sinks (hereafter referred VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 to as ‘‘the Inventory’’) and other analyses produced by the EPA; • Revisions to expand source categories or add new source categories to address potential gaps in reporting of data on U.S. GHG emissions or supply in order to improve the accuracy and completeness of the data provided by the GHGRP; • Amendments to update emission factors to incorporate new measurement data that more accurately reflect industry emissions; • Revisions to refine existing emissions calculation methodologies to reflect an improved understanding of emissions sources and end uses of GHGs, or to incorporate more recent research on GHG emissions or formation; • Additions or modifications to reporting requirements to eliminate data gaps and improve verification of emissions estimates; and • Revisions that clarify requirements that reporters have previously found vague to ensure that accurate data are being collected, and editorial corrections or harmonizing changes that will improve the public’s understanding of the rule. Second, the EPA identified revisions that would streamline the calculation, monitoring, or reporting requirements of part 98 to provide flexibility or increase the efficiency of data collection. In the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Notice, the EPA identified several streamlining revisions that we are finalizing in this rule, as follows: • Revisions to applicability criteria for certain industry sectors without the 25,000 mtCO2e per year reporting threshold to account for changes in usage of certain GHGs, or where the current applicability estimation methodology may overestimate emissions; • Revisions that provide flexibility for and simplify monitoring and calculation methods where further monitoring and data collection will not likely significantly improve our understanding of emission sources at this time, or where we currently allow similar less burdensome methodologies for other sources; and • Revisions to reported data elements or recordkeeping where the current requirements are redundant or where reported data are not currently useful for verification or analysis, or for which continued collection of the data at the same frequency will not likely provide new insights or knowledge of the industry sector, emissions, or trends at this time. PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 The revisions included in this final rule will advance the EPA’s goal of updating the GHGRP to reflect advances in scientific knowledge, better reflect the EPA’s current understanding of U.S. GHG emissions and trends and improve data collection and reporting to better understand emissions from specific sectors or inform future policy decisions under the CAA. The types of streamlining revisions we are finalizing will simplify requirements while maintaining the quality of the data collected under part 98, where continued collection of information assists in evaluation and support of EPA programs and policies. The EPA has frequently considered and relied on data collected under the GHGRP to carry out provisions of the CAA; to inform policy options; and to support regulatory and non-regulatory actions. For example, GHGRP landfill data from subpart HH of part 98 (Municipal Solid Waste Landfills) were previously analyzed to inform the development of the 2016 new source performance standards (NSPS) and emission guidelines (EG) for landfills (89 FR 59322; August 29, 2016). Specifically, the EPA used data from part 98 reporting to update the characteristics and technical attributes of over 1,200 landfills in the EPA’s landfills data set, as well as to estimate emission reductions and costs, to inform the revised performance standards. Most recently, the EPA used GHGRP data collected under subparts RR (Geologic Sequestration of Carbon Dioxide) and UU (Injection of Carbon Dioxide) of part 98 to inform the development of the proposed NSPS and EG for GHG emissions from fossil fuel-fired electric generating units (EGUs) (88 FR 33240, May 23, 2023, hereafter ‘‘EGU NSPS/EG proposed rule’’), including to assess the geographic availability of geologic sequestration and enhanced oil recovery. These final revisions to the GHGRP will, as discussed herein, improve the GHG emissions data and supplier data that is collected under the GHGRP to better inform the EPA in carrying out provisions of the CAA (such as providing a better understanding of upstream production, downstream emissions, and potential impacts) and otherwise supporting the continued development of climate and air quality standards under the CAA. As the EPA has explained since the GHGRP was first promulgated, the data also will inform the EPA’s implementation of CAA section 103(g) regarding improvements in nonregulatory strategies and technologies for preventing or reducing air pollutants (e.g., EPA’s voluntary E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 GHG reduction programs such as the non-CO2 partnership programs and ENERGY STAR) (74 FR 56265). The final rule will support the overall goals of the GHGRP to collect high-quality GHG data and to incorporate metrics and methodologies that reflect scientific updates. For example, we are finalizing revisions to table A–1 to subpart A of part 98 to update the chemical-specific GWP values of certain GHGs to (1) reflect GWPs from the Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (hereinafter referred to as ‘‘AR5’’); 2 (2) for certain GHGs that do not have chemical-specific GWPs listed in AR5, to adopt GWP values from the IPCC Sixth Assessment Report (hereinafter referred to as ‘‘AR6’’); 3 and (3) to revise and expand the set of default GWPs which are applied to GHGs for which peer-reviewed chemical-specific GWPs are not available. In several cases, we are finalizing updates to emissions and default factors where we have received or identified updated measurement data. For example, we are finalizing updates to the default biogenic fraction for tire combustion in subpart C of part 98 (General Stationary Fuel Combustion) based on updated data obtained by the EPA on the weighted average composition of natural rubber in tires, allowing for the estimation of an emission factor that is more representative of these sources. Similarly, we are finalizing updates to the emission factors and default destruction and removal efficiency values in subpart I of part 98 (Electronics Manufacturing). The updated emission factors are based on 2 IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative Efficiencies and Metric Values, which appears on pp. 731–737 of Chapter 8, ‘‘Anthropogenic and Natural Radiative Forcing.’’ 3 Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P. Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The Earth’s Energy Budget, Climate Feedbacks, and Climate Sensitivity Supplementary Material. In Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc ¸i, R. Yu, and B. Zhou (eds.)]. Available from www.ipcc.ch/ The AR6 GWPs are listed in table 7.SM.7, which appears on page 16 of the Supplementary Material. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 newly submitted data from the 2017 and 2020 technology assessment reports submitted under the GHGRP with RY2016 and RY2019 annual reports, as well as consideration of new emission factors available in the 2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (hereafter ‘‘2019 Refinement’’).4 In other cases, we are finalizing updates to calculation methodologies to incorporate updates that are based on an improved understanding of emission sources. For example, for subpart I of part 98 (Electronics Manufacturing), the EPA is implementing emissions estimation improvements from the 2019 Refinement such as updates to the method used to calculate the fraction of fluorinated input gases and byproducts exhausted from tools with abatement systems during stack tests; revising equations that calculate the weighted average DREs for individual fluorinated greenhouse gases (F–GHGs) across process types; requiring that all stack systems be tested if the stack test method is used; and updating a set of equations that will more accurately account for emissions when pre-control emissions of a F–GHG approach or exceed the consumption of that gas during the test period. For subpart Y (Petroleum Refineries), we are amending the calculation methodology for delayed coking units to more accurately reflect the activities conducted at certain facilities that were not captured by the current emissions estimation methodology, which relies on a steam generation model. The incorporation of updated metrics and methodologies will improve the quality and accuracy of the data collected under the GHGRP, increase the Agency’s understanding of the relative distribution of GHGs that are emitted, and better inform EPA policy and programs under the CAA. The improvements to part 98 will further provide a more comprehensive, nationwide GHG emissions profile reflective of the origin and distribution of GHG emissions in the United States and will more accurately inform EPA policy options for potential regulatory or non-regulatory CAA programs. The EPA is finalizing several amendments that will reduce gaps in the reporting of GHG emissions and supply from specific sectors, including the broadening of existing source categories; 4 Intergovernmental Panel on Climate Change. 2019 Refinement to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Calvo Buendia, E., Tanabe, K., Kranjc, A., Baasansuren, J., Fukuda, M., Ngarize, S., Osako, A., Pyrozhenko, Y., Shermanau, P. and Federici, S. (eds). Published: IPCC, Switzerland. 2019. https://www.ipcc-nggip. iges.or.jp/public/2019rf/. PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 31809 and establishing new source categories that will add calculation, monitoring, reporting, and recordkeeping requirements for certain sectors of the economy. The final revisions add five new source categories, including coke calcining; ceramics manufacturing; calcium carbide production; caprolactam, glyoxal, and glyoxylic acid production; and facilities conducting geologic sequestration of carbon dioxide with enhanced oil recovery. These source categories were identified upon evaluation of emission sources that potentially contribute significant GHG emissions that are not currently reported or where facilities representative of these source categories may currently report under another part 98 source category using methodologies that may not provide complete or accurate emissions. Additionally, the inclusion of certain source categories will improve the completeness of the emissions estimates presented in the Inventory, such as collection of data on ceramics manufacturing; calcium carbide production; and caprolactam, glyoxal, and glyoxylic acid production. The EPA is also finalizing updates to certain subparts to add reporting of new emissions or emissions sources for existing sectors to address potential gaps in reporting. For example, we are adding requirements for the monitoring, calculation, and reporting of F–GHGs other than sulfur hexafluoride (SF6) and perfluorocarbons (PFCs) under subparts DD (Electrical Equipment and Distribution Equipment Use) and SS (Electrical Equipment Manufacture or Refurbishment) to account for the introduction of alternative technologies and replacements for SF6. Likewise, we are finalizing revisions that will improve reporting under subpart HH to better account for CH4 emissions from these facilities. Following review of recent studies indicating that CH4 emissions from landfills may be considerably higher than what is currently reported to part 98 due in part to emissions from poorly operating gas collection systems or destruction devices, we are revising the calculation methodologies in subpart HH to better account for these scenarios. These changes are necessary for the EPA to continue to analyze the relative emissions and distribution of emissions from specific industries, improve the overall quality of the data collected under the GHGRP, and better inform future EPA policy and programs under the CAA. For example, the final revisions to subpart HH will be used to further improve the data in the EPA’s landfills data set by providing more E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31810 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations comprehensive and accurate information on landfill emissions and the efficacy of gas collection systems and destruction devices. The final revisions also help ensure that the data collected in the GHGRP can be compared to the data collected and presented by other EPA programs under the CAA. For example, we are finalizing several revisions to the reporting requirements for subpart HH, including more clearly identifying reporting elements associated with each gas collection system, each measurement location within a gas collection system, and each control device associated with a measurement location in subpart HH of part 98. These revisions can be used to estimate the relative volume of gas flared versus sent to landfill-gas-to-energy projects to better understand the amount of recovered CH4 that is beneficially used in energy recovery projects. Understanding the energy recovery of these facilities is critical for evaluating and identifying progress towards renewable energy targets. Specifically, these data will allow the Agency to identify industry-specific trends of beneficial use of landfill gas, communicate best operating practices for reducing GHG emissions, and evaluate options for expanding the use of these best practices or other potential policy options under the CAA. Similarly, we are finalizing revisions to clarify subpart RR (Geologic Sequestration of Carbon Dioxide) and add subpart VV (Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916) to part 98. Subpart VV provides for the reporting of incidental CO2 storage associated with enhanced oil recovery based on the CSA Group (CSA)/American National Standards Institute (ANSI) International Standards Organization (ISO) 27916:19. In the EGU NSPS/EG proposed rule, the EPA proposed that any affected EGU that employs CCS technology that captures enough CO2 to meet the proposed standard and injects the CO2 underground must assure that the CO2 is managed at a facility reporting under subpart RR or new subpart VV of part 98. As such, this final rule complements the EGU NSPS/EG proposed rule. In other cases, the revisions include collection of data that could be compared to other national and international inventories, improving, for example, the estimates provided to the Inventory. For instance, we are finalizing revisions to subpart N (Glass Production) to require reporting of the annual quantities of cullet (i.e., recycled scrap glass) used as a raw material. Because differences in the quantities of VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 cullet used can lead to variations in emissions from the production of different glass types, the annual quantities of cullet used will provide a useful metric for understanding variations and differences in emissions estimates as well as improve the analysis, transparency, and accuracy of the glass manufacturing sector in the Inventory and other EPA programs. Likewise, the addition of reporting for new source categories will improve the completeness of the emissions estimates presented in the Inventory, such as collection of data on ceramics manufacturing, calcium carbide production, and caprolactam, glyoxal, and glyoxylic acid production. The EPA is finalizing several amendments to improve verification of the annual GHG reports. For example, we are finalizing amendments to subpart H (Cement Production) to collect additional data including annual averages for certain chemical composition input data on a facilitybasis, which the Agency will use to build verification checks. These edits will provide the EPA the ability to check reported emissions data from subpart H reporters using both the mass balance and direct measurement estimation methods, allowing the EPA to back-estimate process emissions, which will result in more accurate reporting. Similarly, we are amending subparts OO (Suppliers of Industrial Greenhouse Gases) and QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment or Closed-Cell Foams) of part 98 to require reporting of the Harmonized Tariff System code for each F–GHG, fluorinated heat transfer fluid (F–HTF), or nitrous oxide (N2O) shipped, which will reduce instances of reporting where the data provided is unclear or unable to be compared to outside data sources for verification. Lastly, the changes in this final rule will further advance the ability of the GHGRP to provide access to quality data on greenhouse gas emissions. Since its implementation, the collection of data under the GHGRP has allowed the Agency and relevant stakeholders to identify changes in industry and emissions trends, such as transitions in equipment technology or use of alternative lower-GWP greenhouses gases, that may be beneficial for informing other EPA programs under the CAA. The GHGRP provides an important data resource for communities and the public to understand GHG emissions. Since facilities are required to use prescribed calculation and monitoring methods, emissions data can be compared and PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 analyzed, including locations of emissions sources. GHGRP data are easily accessible to the public via the EPA’s online data publication tool, also known as FLIGHT at: https://ghgdata. epa.gov/ghgp/main.do. FLIGHT allows users to view and sort GHG data for every reporting year starting with 2010 from over 8,000 entities in a variety of ways including by location, industrial sector, and type of GHG emitted. This powerful data resource provides a critical tool for communities to identify nearby sources of GHGs and provide information to state and local governments. Overall, the final revisions in this action will improve the quality of the data collected under the program and available to communities. These final revisions will, as such, maximize the effectiveness of part 98. Section III. of this preamble describes the specific changes that we are finalizing for each subpart to part 98 in more detail. Additional discussion of the benefits of the final rule are in section VII. of this preamble. Additionally, we are finalizing a technical amendment to 40 CFR part 9 to update the table that lists the OMB control numbers issued under the PRA to include the information collection request (ICR) for 40 CFR part 98. This amendment satisfies the display requirements of the PRA and OMB’s implementing regulations at 5 CFR part 1320 and is further described in section IV. of this preamble. III. Final Revisions to Each Subpart of Part 98 and Summary of Comments and Responses This section summarizes the final amendments to each part 98 subpart, as generally described in section II. of this preamble. Major changes to the final rule as compared to the proposed revisions are identified in this section. The amendments to each subpart are followed by a summary of the major comments on those amendments, and the EPA’s responses to those comments. Other minor corrections and clarifications are reflected in the final redline regulatory text in the docket for this rulemaking (Docket ID. No. EPA– HQ–OAR–2019–0424). A. Subpart A—General Provisions The EPA is finalizing several amendments to subpart A of part 98 (General Provisions) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.A.1. of this preamble discusses the final revisions to subpart A. The EPA received several comments on the proposed subpart A revisions which are discussed in section III.A.2. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations of this preamble. We are not finalizing the proposed confidentiality determinations for data elements that were included in the proposed revisions to subpart A, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart A This section summarizes the final amendments to subpart A. Major changes in this final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart A can be found in section III.A.2. of this preamble. Additional information for these amendments and their supporting basis is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. lotter on DSK11XQN23PROD with RULES2 a. Revisions to Global Warming Potentials As proposed, we are revising table A– 1 to subpart A of part 98 to reflect more accurate GWPs to better characterize the climate impacts of individual GHGs and to ensure continued consistency with other U.S. climate programs, including the Inventory. The amendments to the GWPs in table A–1 that we are finalizing in this document are discussed in this section of this preamble. The EPA’s response to comments received on the proposed revisions to table A–1 are in section III.A.2.a. of this preamble. In the 2022 Data Quality Improvements Proposal, the EPA proposed two updates to table A–1 to subpart A of part 98 to update GWP values to reflect advances in scientific knowledge. First, we proposed to adopt a chemical-specific GWP of 0.14 for carbonic difluoride (COF2) using the atmospheric lifetime and radiative efficiency published by the World Meteorological Organization (WMO) in its Scientific Assessment of Ozone Depletion.5 We also proposed to expand one of the F–GHG groups to which a default GWP is assigned. Default GWPs are applied to GHGs for which peerreviewed chemical-specific GWPs are not available. Specifically, we proposed to expand the ninth F–GHG group in 5 WMO. Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project–Report No. 58, 588 pp., Geneva, Switzerland, 2018. www.esrl.noaa.gov/csd/ assessments/ozone/2018/downloads/ 018OzoneAssessment.pdf. Retrieved July 29, 2019. Available in the docket for this rulemaking, Docket ID. No. EPA–HQ–OAR–2019–0424. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 table A–1 to subpart A of part 98, which includes unsaturated PFCs, unsaturated HFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated ketones, to include additional unsaturated fluorocarbons. Given the very short atmospheric lifetimes of unsaturated GHGs and review of available evaluations of individual unsaturated chlorofluorocarbons and unsaturated bromofluorocarbons in the 2018 WMO Scientific Assessment, we proposed to add unsaturated bromofluorocarbons, unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons, unsaturated hydrobromofluorocarbons, and unsaturated hydrobromochlorofluorocarbons to this F–GHG group, which will apply a default GWP of 1 to these compounds. Additional information on these amendments and their supporting basis is available in section III.A.1. of the preamble to the 2022 Data Quality Improvements Proposal. As the 2022 Data Quality Improvements Proposal was nearing publication, the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) fully specified which GWPs countries should use for purposes of GHG reporting.6 The EPA subsequently proposed a comprehensive update to table A–1 to subpart A of part 98 in the 2023 Supplemental Proposal, consistent with recent science and the UNFCCC decision. This update carried out the intent that the EPA expressed at the time the GHGRP was first promulgated and in subsequent updates to part 98 to periodically update table A–1 as science and UNFCCC decisions evolve. Specifically, the EPA proposed revisions to table A–1 to update the chemical-specific GWPs values of certain GHGs to reflect values from the IPCC AR5 7 and, for certain GHGs that 6 As explained in section III.A.1. of the preamble to the 2023 Supplemental Proposal, the Parties to the UNFCCC specified the agreed-on GWPs in November 2021, which was too late to allow the EPA to consider proposing a comprehensive GWP update in the 2022 Data Quality Improvement Proposal. 7 IPCC, 2013: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 31811 do not have chemical-specific GWPs listed in AR5, to adopt GWP values from the IPCC AR6.8 We proposed to adopt the AR5 and AR6 GWPs based on a 100year time horizon. We also proposed to revise and expand the set of default GWPs in table A–1 for GHGs for which peer-reviewed chemical-specific GWPs are not available, including adding two new fluorinated GHG groups for saturated chlorofluorocarbons (CFCs) and for cyclic forms of unsaturated halogenated compounds, modifying the ninth F–GHG group to more clearly apply to non-cyclic unsaturated halogenated compounds, and updating the existing default GWP values to reflect values estimated from the chemical-specific GWPs that we proposed to adopt from AR5 and AR6. See sections II.A. and III.A.1. of the preamble to the 2023 Supplemental Proposal for additional information. As proposed, we are amending table A–1 to subpart A of part 98 to update and add chemical-specific and default GWPs. Consistent with the 2021 UNFCCC decision, we are updating table A–1 to use, for GHGs with GWPs in AR5, the AR5 GWP values in table 8.A.1 (that reflect the climate-carbon feedbacks of CO2 but not the GHG whose GWP is being evaluated), and for CH4, the GWP that is not the GWP for fossil CH4 in table 8.A.1 (i.e., the GWP for CH4 that does not reflect either the climate-carbon feedbacks for CH4 or the atmospheric CO2 that would result from the oxidation of CH4 in the atmosphere). We are also updating table A–1 to adopt AR6 GWP values for 31 F–GHGs that have GWPs listed in AR6 but not AR5. Table 2 of this preamble lists the final GWP values for each GHG. Press, Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative Efficiencies and Metric Values, which appears on pp. 731–737 of Chapter 8, ‘‘Anthropogenic and Natural Radiative Forcing.’’ 8 Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P. Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The Earth’s Energy Budget, Climate Feedbacks, and Climate Sensitivity Supplementary Material. In Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc ¸i, R. Yu, and B. Zhou (eds.)]. Available from: www.ipcc.ch/. The AR6 GWPs are listed in table 7.SM.7, which appears on page 16 of the Supplementary Material. E:\FR\FM\25APR2.SGM 25APR2 31812 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE 2—REVISED CHEMICAL-SPECIFIC GWPS FOR COMPOUNDS IN TABLE A–1 Name CAS No. Chemical formula GWP (100-year) Chemical-Specific GWPs Carbon dioxide ............................................................................................................. Methane ....................................................................................................................... Nitrous oxide ................................................................................................................ 124–38–9 74–82–8 10024–97–2 CO2 ........................................................... CH4 ........................................................... N2O ........................................................... 1 28 265 SF6 ........................................................... SF5CF3 ..................................................... NF3 ........................................................... CF4 ........................................................... C2F6 .......................................................... C3F8 .......................................................... c-C3F6 ....................................................... C4F10 ........................................................ c-C4F8 ....................................................... c-C4F8O .................................................... C5F12 ........................................................ C6F14 ........................................................ C7F16; CF3(CF2)5CF3 ............................... C8F18; CF3(CF2)6CF3 ............................... C10F18 ....................................................... CF3OCF(CF3)CF2OCF2OCF3 .................. Z–C10F18 .................................................. E–C10F18 .................................................. N(C2F5)3 ................................................... N(CF2CF2CF3)3 ........................................ N(CF2CF2CF2CF3)3 .................................. N(CF2CF2CF2CF2CF3)3 ........................... 23,500 17,400 16,100 6,630 11,100 8,900 9,200 9,200 9,540 13,900 8,550 7,910 7,820 7,620 7,190 9,710 7,240 6,290 10,300 9,030 8,490 7,260 Fully Fluorinated GHGs Sulfur hexafluoride ....................................................................................................... Trifluoromethyl sulphur pentafluoride ........................................................................... Nitrogen trifluoride ........................................................................................................ PFC–14 (Perfluoromethane) ........................................................................................ PFC–116 (Perfluoroethane) ......................................................................................... PFC–218 (Perfluoropropane) ....................................................................................... Perfluorocyclopropane ................................................................................................. PFC–3–1–10 (Perfluorobutane) ................................................................................... PFC–318 (Perfluorocyclobutane) ................................................................................. Perfluorotetrahydrofuran .............................................................................................. PFC–4–1–12 (Perfluoropentane) ................................................................................. PFC–5–1–14 (Perfluorohexane, FC–72) ..................................................................... PFC–6–1–12 ................................................................................................................ PFC–7–1–18 ................................................................................................................ PFC–9–1–18 ................................................................................................................ PFPMIE (HT–70) .......................................................................................................... Perfluorodecalin (cis) ................................................................................................... Perfluorodecalin (trans) ................................................................................................ Perfluorotriethylamine .................................................................................................. Perfluorotripropylamine ................................................................................................ Perfluorotributylamine .................................................................................................. Perfluorotripentylamine ................................................................................................ 2551–62–4 373–80–8 7783–54–2 75–73–0 76–16–4 76–19–7 931–91–9 355–25–9 115–25–3 773–14–8 678–26–2 355–42–0 335–57–9 307–34–6 306–94–5 NA 60433–11–6 60433–12–7 359–70–6 338–83–0 311–89–7 338–84–1 Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds (4s,5s)-1,1,2,2,3,3,4,5-octafluorocyclopentane ............................................................ HFC–23 ........................................................................................................................ HFC–32 ........................................................................................................................ HFC–125 ...................................................................................................................... HFC–134 ...................................................................................................................... HFC–134a .................................................................................................................... HFC–227ca .................................................................................................................. HFC–227ea .................................................................................................................. HFC–236cb .................................................................................................................. HFC–236ea .................................................................................................................. HFC–236fa ................................................................................................................... HFC–329p .................................................................................................................... HFC–43–10mee ........................................................................................................... 158389–18–5 75–46–7 75–10–5 354–33–6 359–35–3 811–97–2 220732–84–8 431–89–0 677–56–5 431–63–0 690–39–1 375–17–7 138495–42–8 trans-cyc (-CF2CF2CF2CHFCHF-) ........... CHF3 ......................................................... CH2F2 ....................................................... C2HF5 ....................................................... C2H2F4 ...................................................... CH2FCF3 .................................................. CF3CF2CHF2 ............................................ C3HF7 ....................................................... CH2FCF2CF3 ............................................ CHF2CHFCF3 ........................................... C3H2F6 ...................................................... CHF2CF2CF2CF3 ...................................... CF3CFHCFHCF2CF3 ................................ 258 12,400 677 3,170 1,120 1,300 2,640 3,350 1,210 1,330 8,060 2,360 1,650 Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds 1,1,2,2,3,3-hexafluorocyclopentane ............................................................................. 1,1,2,2,3,3,4-heptafluorocyclopentane ......................................................................... HFC–41 ........................................................................................................................ HFC–143 ...................................................................................................................... HFC–143a .................................................................................................................... HFC–10732 .................................................................................................................. HFC–10732a ................................................................................................................ HFC–161 ...................................................................................................................... HFC–245ca .................................................................................................................. HFC–245cb .................................................................................................................. HFC–245ea .................................................................................................................. HFC–245eb .................................................................................................................. HFC–245fa ................................................................................................................... HFC–263fb ................................................................................................................... HFC–272ca .................................................................................................................. HFC–365mfc ................................................................................................................ 123768–18–3 1073290–77–4 593–53–3 430–66–0 420–46–2 624–72–6 75–37–6 353–36–6 679–86–7 1814–88–6 24270–66–4 431–31–2 460–73–1 421–07–8 420–45–1 406–58–6 cyc (-CF2CF2CF2CH2CH2-) ...................... cyc (-CF2CF2CF2CHFCH2-) ..................... CH3F ......................................................... C2H3F3 ...................................................... C2H3F3 ...................................................... CH2FCH2F ................................................ CH3CHF2 .................................................. CH3CH2F .................................................. C3H3F5 ...................................................... CF3CF2CH3 .............................................. CHF2CHFCHF2 ........................................ CH2FCHFCF3 ........................................... CHF2CH2CF3 ............................................ CH3CH2CF3 .............................................. CH3CF2CH3 .............................................. CH3CF2CH2CF3 ....................................... 120 231 116 328 4,800 16 138 4 716 4,620 235 290 858 76 144 804 Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond lotter on DSK11XQN23PROD with RULES2 HFE–125 ...................................................................................................................... HFE–227ea .................................................................................................................. HFE–329mcc2 .............................................................................................................. HFE–329me3 ............................................................................................................... 1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-propane ................................. 3822–68–2 2356–62–9 134769–21–4 428454–68–6 3330–15–2 CHF2OCF3 ............................................... CF3CHFOCF3 ........................................... CF3CF2OCF2CHF2 ................................... CF3CFHCF2OCF3 .................................... CF3CF2CF2OCHFCF3 .............................. 12,400 6,450 3,070 4,550 6,490 Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds HFE–134 (HG–00) ....................................................................................................... HFE–236ca .................................................................................................................. HFE–236ca12 (HG–10) ............................................................................................... HFE–236ea2 (Desflurane) ........................................................................................... HFE–236fa ................................................................................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00012 Fmt 4701 1691–17–4 32778–11–3 7807322–47–1 57041–67–5 20193–67–3 Sfmt 4700 CHF2OCHF2 ............................................. CHF2OCF2CHF2 ....................................... CHF2OCF2OCHF2 .................................... CHF2OCHFCF3 ........................................ CF3CH2OCF3 ........................................... E:\FR\FM\25APR2.SGM 25APR2 5,560 4,240 5,350 1,790 979 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31813 TABLE 2—REVISED CHEMICAL-SPECIFIC GWPS FOR COMPOUNDS IN TABLE A–1—Continued Name CAS No. HFE–338mcf2 .............................................................................................................. HFE–338mmz1 ............................................................................................................ HFE–338pcc13 (HG–01) .............................................................................................. HFE–43–10pccc (H-Galden 1040x, HG–11) ............................................................... HCFE–235ca2 (Enflurane) ........................................................................................... HCFE–235da2 (Isoflurane) .......................................................................................... HG–02 .......................................................................................................................... HG–03 .......................................................................................................................... HG–20 .......................................................................................................................... HG–21 .......................................................................................................................... HG–30 .......................................................................................................................... 1,1,3,3,4,4, 6,6,7,7,9,9, 10,10,12,12, 13,13,15, 15-eicosafluoro-2,5,8,11,14Pentaoxapentadecane. 1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane .................................................................. Trifluoro(fluoromethoxy)methane ................................................................................. Chemical formula GWP (100-year) 156053–88–2 26103–08–2 188690–78–0 E1730133 13838–16–9 26675–46–7 205367–61–9 173350–37–3 249932–25–0 249932–26–1 188690–77–9 173350–38–4 CF3CF2OCH2CF3 ..................................... CHF2OCH(CF3)2 ...................................... CHF2OCF2CF2OCHF2 ............................. CHF2OCF2OC2F4OCHF2 ......................... CHF2OCF2CHFCl ..................................... CHF2OCHClCF3 ....................................... HF2C-(OCF2CF2)2-OCF2H ....................... HF2C-(OCF2CF2)3-OCF2H ....................... HF2C-(OCF2)2-OCF2H ............................. HF2C-OCF2CF2OCF2OCF2O-CF2H ......... HF2C-(OCF2)3-OCF2H ............................. HCF2O(CF2CF2O)4CF2H ......................... 929 2,620 2,910 2,820 583 491 2,730 2,850 5,300 3,890 7,330 3,630 84011–06–3 2261–01–0 CHF2CHFOCF3 ........................................ CH2FOCF3 ............................................... 1,240 751 Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds HFE–143a .................................................................................................................... HFE–245cb2 ................................................................................................................ HFE–245fa1 ................................................................................................................. HFE–245fa2 ................................................................................................................. HFE–254cb1 ................................................................................................................ HFE–263fb2 ................................................................................................................. HFE–263m1; R–E–143a .............................................................................................. HFE–347mcc3 (HFE–7000) ......................................................................................... HFE–347mcf2 .............................................................................................................. HFE–347mmy1 ............................................................................................................ HFE–347mmz1 (Sevoflurane) ...................................................................................... HFE–347pcf2 ............................................................................................................... HFE–356mec3 ............................................................................................................. HFE–356mff2 ............................................................................................................... HFE–356mmz1 ............................................................................................................ HFE–356pcc3 ............................................................................................................... HFE–356pcf2 ............................................................................................................... HFE–356pcf3 ............................................................................................................... HFE–365mcf2 .............................................................................................................. HFE–365mcf3 .............................................................................................................. HFE–374pc2 ................................................................................................................ HFE–449s1 (HFE–7100) Chemical blend ................................................................... HFE–569sf2 (HFE–7200) Chemical blend .................................................................. HFE–7300 .................................................................................................................... HFE–7500 .................................................................................................................... HG′-01 .......................................................................................................................... HG′-02 .......................................................................................................................... HG′-03 .......................................................................................................................... Difluoro(methoxy)methane ........................................................................................... 2-Chloro-1,1,2-trifluoro-1-methoxyethane .................................................................... 1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane .................................................................. 2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-bis[1,2,2,2-tetrafluoro-1(trifluoromethyl)ethyl]-furan. 1-Ethoxy-1,1,2,3,3,3-hexafluoropropane ...................................................................... Fluoro(methoxy)methane ............................................................................................. 1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3-tetrafluoropropyl ether .......... 1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane ............................................................... Difluoro(fluoromethoxy)methane .................................................................................. Fluoro(fluoromethoxy)methane .................................................................................... 421–14–7 22410–44–2 84011–15–4 1885–48–9 425–88–7 460–43–5 690–22–2 375–03–1 171182–95–9 2200732–84–2 2807323–86–6 406–78–0 382–34–3 333–36–8 13171–18–1 160620–20–2 50807–77–7 35042–99–0 2200732–81–9 378–16–5 512–51–6 163702–07–6 163702–08–7 163702–05–4 163702–06–5 132182–92–4 297730–93–9 73287–23–7 485399–46–0 485399–48–2 359–15–9 425–87–6 22052–86–4 920979–28–8 CH3OCF3 .................................................. CH3OCF2CF3 ........................................... CHF2CH2OCF3 ......................................... CHF2OCH2CF3 ......................................... CH3OCF2CHF2 ......................................... CF3CH2OCH3 ........................................... CF3OCH2CH3 ........................................... CH3OCF2CF2CF3 ..................................... CF3CF2OCH2CHF2 .................................. CH3OCF(CF3)2 ......................................... (CF3)2CHOCH2F ...................................... CHF2CF2OCH2CF3 .................................. CH3OCF2CHFCF3 .................................... CF3CH2OCH2CF3 ..................................... (CF3)2CHOCH3 ......................................... CH3OCF2CF2CHF2 .................................. CHF2CH2OCF2CHF2 ................................ CHF2OCH2CF2CHF2 ................................ CF3CF2OCH2CH3 ..................................... CF3CF2CH2OCH3 ..................................... CH3CH2OCF2CHF2 .................................. C4F9OCH3 ................................................ (CF3)2CFCF2OCH3. C4F9OC2H5 ............................................... (CF3)2CFCF2OC2H5. (CF3)2CFCFOC2H5CF2CF2CF3 ................ n-C3F7CFOC2H5CF(CF3)2 ....................... CH3OCF2CF2OCH3 .................................. CH3O(CF2CF2O)2CH3 .............................. CH3O(CF2CF2O)3CH3 .............................. CH3OCHF2 ............................................... CH3OCF2CHFCl ....................................... CF3CF2CF2OCH2CH3 .............................. C12H5F19O2 .............................................. 523 654 828 812 301 1 29 530 854 363 216 889 387 17 14 413 719 446 58 0.99 627 421 380–34–7 460–22–0 60598–17–6 37031–31–5 461–63–2 462–51–1 CF3CHFCF2OCH2CH3 ............................. CH3OCH2F ............................................... CHF2CF2CH2OCH3 .................................. CH2FOCF2CF2H ....................................... CH2FOCHF2 ............................................. CH2FOCH2F ............................................. 23 13 0.49 871 617 130 trans-cyc (-CClFCF2CF2CClF-) ................ cis-cyc (-CClFCF2CF2CClF-) .................... 4,230 5,660 HCOOCF3 ................................................ HCOOCF2CF3 .......................................... HCOOCHFCF3 ......................................... HCOOCF2CF2CF2CF3 ............................. HCOOCF2CF2CF3 .................................... HCOOCH(CF3)2 ....................................... HCOOCH2CF3 .......................................... HCOOCH2CH2CF3 ................................... 588 580 470 392 376 333 33 17 CF3COOCH3 ............................................ CF3COOCF2CH3 ...................................... CF3COOCHF2 .......................................... 52 31 27 57 405 13 222 236 221 144 122 61 56 Saturated Chlorofluorocarbons (CFCs) E–R316c ....................................................................................................................... Z–R316c ....................................................................................................................... 3832–15–3 3934–26–7 lotter on DSK11XQN23PROD with RULES2 Fluorinated Formates Trifluoromethyl formate ................................................................................................ Perfluoroethyl formate .................................................................................................. 1,2,2,2-Tetrafluoroethyl formate ................................................................................... Perfluorobutyl formate .................................................................................................. Perfluoropropyl formate ................................................................................................ 1,1,1,3,3,3-Hexafluoropropan-2-yl formate .................................................................. 2,2,2-Trifluoroethyl formate .......................................................................................... 3,3,3-Trifluoropropyl formate ........................................................................................ 85358–65–2 313064–40–3 481631–19–0 197218–56–7 271257–42–2 856766–70–6 32042–38–9 1344118–09–7 Fluorinated Acetates Methyl 2,2,2-trifluoroacetate ......................................................................................... 1,1-Difluoroethyl 2,2,2-trifluoroacetate ......................................................................... Difluoromethyl 2,2,2-trifluoroacetate ............................................................................ VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00013 Fmt 4701 431–47–0 1344118–13–3 2024–86–4 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31814 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE 2—REVISED CHEMICAL-SPECIFIC GWPS FOR COMPOUNDS IN TABLE A–1—Continued Name CAS No. 2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate ..................................................................... Methyl 2,2-difluoroacetate ............................................................................................ Perfluoroethyl acetate .................................................................................................. Trifluoromethyl acetate ................................................................................................. Perfluoropropyl acetate ................................................................................................ Perfluorobutyl acetate .................................................................................................. Ethyl 2,2,2-trifluoroacetate ........................................................................................... 407–38–5 433–53–4 343269–97–6 74123–20–9 1344118–10–0 209597–28–4 383–63–1 Chemical formula GWP (100-year) CF3COOCH2CF3 ...................................... HCF2COOCH3 .......................................... CH3COOCF2CF3 ...................................... CH3COOCF3 ............................................ CH3COOCF2CF2CF3 ................................ CH3COOCF2CF2CF2CF3 ......................... CF3COOCH2CH3 ...................................... 7 3 2 2 2 2 1 FCOOCH3 ................................................ FCOOCF2CH3 .......................................... 95 27 Carbonofluoridates Methyl carbonofluoridate .............................................................................................. 1,1-Difluoroethyl carbonofluoridate .............................................................................. 1538–06–3 1344118–11–1 Fluorinated Alcohols Other Than Fluorotelomer Alcohols Bis(trifluoromethyl)-methanol ....................................................................................... 2,2,3,3,4,4,5,5-Octafluorocyclopentanol ....................................................................... 2,2,3,3,3-Pentafluoropropanol ...................................................................................... 2,2,3,3,4,4,4-Heptafluorobutan-1-ol ............................................................................. 2,2,2-Trifluoroethanol ................................................................................................... 2,2,3,4,4,4-Hexafluoro-1-butanol .................................................................................. 2,2,3,3-Tetrafluoro-1-propanol ..................................................................................... 2,2-Difluoroethanol ....................................................................................................... 2-Fluoroethanol ............................................................................................................ 4,4,4-Trifluorobutan-1-ol ............................................................................................... 920–66–1 16621–87–7 422–05–9 375–01–9 75–89–8 382–31–0 76–37–9 359–13–7 371–62–0 461–18–7 (CF3)2CHOH ............................................. cyc (-(CF2)4CH(OH)-) ............................... CF3CF2CH2OH ......................................... C3F7CH2OH ............................................. CF3CH2OH ............................................... CF3CHFCF2CH2OH ................................. CHF2CF2CH2OH ...................................... CHF2CH2OH ............................................ CH2FCH2OH ............................................. CF3(CH2)2CH2OH .................................... 182 13 19 34 20 17 13 3 1.1 0.05 Non-Cyclic, Unsaturated Perfluorocarbons (PFCs) PFC–1114; TFE ........................................................................................................... PFC–1216; Dyneon HFP ............................................................................................. Perfluorobut-2-ene ....................................................................................................... Perfluorobut-1-ene ....................................................................................................... Perfluorobuta-1,3-diene ................................................................................................ 116–14–3 116–15–4 360–89–4 357–26–6 685–63–2 CF2=CF2; C2F4 ......................................... C3F6; CF3CF=CF2 .................................... CF3CF=CFCF3 ......................................... CF3CF2CF=CF2 ........................................ CF2=CFCF=CF2 ....................................... 0.004 0.05 1.82 0.10 0.003 Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs) HFC–1132a; VF2 ......................................................................................................... HFC–1141; VF ............................................................................................................. (E)-HFC–1225ye .......................................................................................................... (Z)-HFC–1225ye .......................................................................................................... Solstice 1233zd(E) ....................................................................................................... HCFO–1233zd(Z) ......................................................................................................... HFC–1234yf; HFO–1234yf ........................................................................................... HFC–1234ze(E) ........................................................................................................... HFC–1234ze(Z) ............................................................................................................ HFC–1243zf; TFP ........................................................................................................ (Z)-HFC–1336 .............................................................................................................. HFO–1336mzz(E) ........................................................................................................ HFC–1345zfc ............................................................................................................... HFO–1123 .................................................................................................................... HFO–1438ezy(E) ......................................................................................................... HFO–1447fz ................................................................................................................. Capstone 42–U ............................................................................................................ Capstone 62–U ............................................................................................................ Capstone 82–U ............................................................................................................ (e)-1-chloro-2-fluoroethene .......................................................................................... 3,3,3-trifluoro-2-(trifluoromethyl)prop-1-ene ................................................................. 75–38–7 75–02–5 5595–10–8 507328–43–8 102687–65–0 99728–16–2 754–12–1 1645–83–6 29118–25–0 677–21–4 692–49–9 66711–86–2 374–27–6 359–11–5 14149–41–8 355–08–8 19430–93–4 2073291–17–2 2160732–58–4 460–16–2 382–10–5 C2H2F2, CF2=CH2 .................................... C2H3F, CH2=CHF ..................................... CF3CF=CHF(E) ........................................ CF3CF=CHF(Z) ........................................ C3H2ClF3; CHCl=CHCF3 .......................... (Z)-CF3CH=CHCl ...................................... C3H2F4; CF3CF=CH2 ............................... C3H2F4; trans-CF3CH=CHF ..................... C3H2F4; cis-CF3CH=CHF; CF3CH=CHF C3H3F3, CF3CH=CH2 ............................... CF3CH=CHCF3(Z) .................................... (E)-CF3CH=CHCF3 .................................. C2F5CH=CH2 ............................................ CHF=CF2 .................................................. (E)-(CF3)2CFCH=CHF .............................. CF3(CF2)2CH=CH2 ................................... C6H3F9, CF3(CF2)3CH=CH2 ..................... C8H3F13, CF3(CF2)5CH=CH2 ................... C10H3F17, CF3(CF2)7CH=CH2 .................. (E)-CHCl=CHF .......................................... (CF3)2C=CH2 ............................................ 0.04 0.02 0.06 0.22 1.34 0.45 0.31 0.97 0.29 0.12 1.58 18 0.09 0.005 8.2 0.24 0.16 0.11 0.09 0.004 0.38 CClF=CClF ............................................... CCl2=CF2 .................................................. 0.13 0.021 CF3OCF=CF2 ........................................... CF3CH2OCH=CH2 .................................... CH3OC7F13 ............................................... 0.17 0.05 15 CF3COOCH=CH2 ..................................... CF3COOCH2CH=CH2 .............................. 0.008 0.007 c-C5F8 ....................................................... cyc (-CF=CFCF2CF2-) .............................. cyc (-CF2CF2CF2CF=CH-) ....................... cyc (-CH=CFCF2CF2-) ............................. cyc (-CH=CHCF2CF2-) ............................. 2 126 45 92 26 Non-Cyclic, Unsaturated CFCs CFC–1112 .................................................................................................................... CFC–1112a .................................................................................................................. 598–88–9 79–35–6 Non-Cyclic, Unsaturated Halogenated Ethers PMVE; HFE–216 .......................................................................................................... Fluoroxene ................................................................................................................... Methyl-perfluoroheptene-ethers ................................................................................... 1187–93–5 406–90–6 N/A Non-Cyclic, Unsaturated Halogenated Esters lotter on DSK11XQN23PROD with RULES2 Ethenyl 2,2,2-trifluoroacetate ....................................................................................... Prop-2-enyl 2,2,2-trifluoroacetate ................................................................................. 433–28–3 383–67–5 Cyclic, Unsaturated HFCs and PFCs PFC C–1418 ................................................................................................................ Hexafluorocyclobutene ................................................................................................. 1,3,3,4,4,5,5-heptafluorocyclopentene ......................................................................... 1,3,3,4,4-pentafluorocyclobutene ................................................................................. 3,3,4,4-tetrafluorocyclobutene ...................................................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00014 Fmt 4701 559–40–0 697–11–0 1892–03–1 374–31–2 2714–38–7 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31815 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE 2—REVISED CHEMICAL-SPECIFIC GWPS FOR COMPOUNDS IN TABLE A–1—Continued Name CAS No. Chemical formula GWP (100-year) Fluorinated Aldehydes 3,3,3-Trifluoro-propanal ................................................................................................ 460–40–2 CF3CH2CHO ............................................. 0.01 756–13–8 421–50–1 381–88–4 CF3CF2C(O)CF(CF3)2 .............................. CF3COCH3 ............................................... CF3COCH2CH3 ........................................ 0.1 0.09 0.095 185689–57–0 2240–88–2 755–02–2 87017–97–8 CF3(CF2)4CH2CH2OH .............................. CF3CH2CH2OH ........................................ CF3(CF2)6CH2CH2OH .............................. CF3(CF2)8CH2CH2OH .............................. 0.43 0.35 0.33 0.19 Fluorinated Ketones Novec 1230 (perfluoro (2-methyl-3-pentanone)) ......................................................... 1,1,1-trifluoropropan-2-one ........................................................................................... 1,1,1-trifluorobutan-2-one ............................................................................................. Fluorotelomer 3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol ............................................................. 3,3,3-Trifluoropropan-1-ol ............................................................................................. 3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol ............................................. 3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-Nonadecafluoroundecan-1-ol .................... Fluorinated GHGs With Carbon-Iodine Bond(s) Trifluoroiodomethane ................................................................................................... 2314–97–8 CF3I .......................................................... 0.4 Remaining Fluorinated GHGs with Chemical-Specific GWPs Dibromodifluoromethane (Halon 1202) ........................................................................ 2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-2311/Halothane) ................................ Heptafluoroisobutyronitrile ............................................................................................ Carbonyl fluoride .......................................................................................................... As proposed, we are also amending table A–1 to subpart A of part 98 to revise the default GWPs. We are modifying the default GWP groups to add a group for saturated CFCs and a group for cyclic forms of unsaturated halogenated compounds. Based on the numerical differences between the GWP for cyclic unsaturated halogenated compounds and non-cyclic unsaturated halogenated compounds, we are also modifying the ninth F–GHG group to reflect non-cyclic forms of unsaturated halogenated compounds. The amendments update the default GWPs of each group based on the average of the updated chemical-specific GWPs (adopted from either the IPCC AR5 or AR6) for the compounds that belong to that group. We are also finalizing our proposal to rename the fluorinated GHG group ‘‘Other fluorinated GHGs’’ to ‘‘Remaining fluorinated GHGs.’’ The new and revised fluorinated GHG groups and their new and revised GWPs are listed in table 3 of this preamble. TABLE 3—FLUORINATED GHG GROUPS AND DEFAULT GWPS FOR TABLE A–1 GWP (100year) lotter on DSK11XQN23PROD with RULES2 Fluorinated GHG group Fully fluorinated GHGs ...................... Saturated hydrofluorocarbons (HFCs) with two or fewer carbon-hydrogen bonds. Saturated HFCs with three or more carbon-hydrogen bonds. VerDate Sep<11>2014 19:27 Apr 24, 2024 9,200 3,000 75–61–6 151–67–7 42532–60–5 353–50–4 TABLE 3—FLUORINATED GHG GROUPS AND DEFAULT GWPS FOR TABLE A–1—Continued Saturated hydrofluoroethers (HFEs) and hydrochlorofluoroethers (HCFEs) with one carbon-hydrogen bond. Saturated HFEs and HCFEs with two carbon-hydrogen bonds. Saturated HFEs and HCFEs with three or more carbon-hydrogen bonds. Saturated chlorofluorocarbons (CFCs). Fluorinated formates .......................... Cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons (BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated hydrobromofluorocarbons (HBFCs), unsaturated hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, and unsaturated halogenated esters. Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols. PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 6,600 2,900 320 4,900 350 58 25 231 41 2,750 0.14 TABLE 3—FLUORINATED GHG GROUPS AND DEFAULT GWPS FOR TABLE A–1—Continued GWP (100year) Fluorinated GHG group 840 Jkt 262001 CBr2F2 ...................................................... CHBrClCF3 ............................................... (CF3)2CFCN ............................................. COF2 ........................................................ Fluorinated GHG group Fluorinated aldehydes, fluorinated ketones, and non-cyclic forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers, and unsaturated halogenated esters. Fluorotelomer alcohols ...................... Fluorinated GHGs with carbon-iodine bond(s). Remaining fluorinated GHGs ............. GWP (100year) 1 1 1 1,800 b. Other Revisions To Improve the Quality of Data Collected for Subpart A The EPA is finalizing several revisions to improve the quality of data collected for subpart A as proposed. In some cases, we are finalizing the proposed amendments with revisions. First, we are clarifying in 40 CFR 98.2(i)(1) and (2), as proposed, that the provision to allow cessation of reporting or ‘‘off-ramping,’’ due to meeting either the 15,000 mtCO2e level or the 25,000 mtCO2e level for the number of years specified in 40 CFR 98.2(i), is based on the CO2e reported, calculated in accordance with 40 CFR 98.3(c)(4)(i) (i.e., the annual emissions report value as specified in that provision). The final amendments also clarify that after an E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31816 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations owner or operator off-ramps, the owner or operator must use equation A–1 to subpart A and follow the requirements of 40 CFR 98.2(b)(4) (the emission estimation methods used for determination of applicability) in subsequent years to determine if emissions exceed the 25,000 mtCO2e applicability threshold and whether the facility or supplier must resume reporting. Additionally, the EPA is amending 40 CFR 98.2(f)(1) and adding new paragraph (k) as proposed to clarify the calculation of GHG quantities for comparison to the 25,000 mtCO2e threshold for importers and exporters of industrial greenhouse gases. The final amendments to 40 CFR 98.2(f)(1) state that importers and exporters must include the F–HTFs that are imported or exported during the year. New paragraph (k) specifies how to calculate the quantities of F–GHGs and F–HTFs destroyed for purposes of comparing them to the 25,000 mtCO2e threshold for stand-alone industrial F–GHG or F–HTF destruction facilities. The EPA is also finalizing as proposed revisions to 40 CFR 98.3(h)(4) to limit the total number of days a reporter can request to extend the time period for resolving a substantive error, either by submitting a revised report or providing information demonstrating that the previously submitted report does not contain the substantive error, to 180 days. Specifically, the Administrator will only approve extension requests for a total of 180 days from the initial notification of a substantive error. See section III.A.1. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. We are finalizing minor clarifications to the reporting and special provisions for best available monitoring methods in 40 CFR 98.3(k) and (l) as proposed, which apply to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 due to amendment(s) to table A–1 to subpart A. The final requirements revise the term ‘‘published’’ to add ‘‘in the Federal Register as a final rulemaking’’ to clarify the EPA’s intent that the requirements apply to facilities or suppliers that are first subject to the GHGRP in the year after the year the GWP is published as part of a final rule. The EPA is finalizing an additional edit to subpart A to the electronic reporting provisions of 40 CFR 98.5(b). The revisions clarify that 40 CFR 98.5(b) applies to any data that is specified as verification software records in a subpart’s applicable recordkeeping section. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 The EPA is finalizing several revisions to subpart A to incorporate new and revised source categories. We are revising tables A–3 and A–4 to subpart A to clarify the reporting applicability for facilities included in the new source categories of coke calcining; ceramics manufacturing; calcium carbide production; caprolactam, glyoxal, and glyoxylic acid production; and facilities conducting geologic sequestration of carbon dioxide with enhanced oil recovery. We are revising table A–3 to subpart A to add new subparts that are ‘‘all-in’’ source categories, including subpart VV (Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916) (section III.AA. of this preamble), subpart WW (Coke Calciners) (section III.BB. of this preamble), subpart XX (Calcium Carbide Production) (section III.CC. of this preamble), and subpart YY (Caprolactam, Glyoxal, and Glyoxylic Acid Production) (section III.DD. of this preamble). We are revising table A–4 to add new subpart ZZ (Ceramics Manufacturing) and assign a threshold of 25,000 mtCO2e, as proposed. As discussed in section III.EE. of this preamble, subpart ZZ to part 98 applies to certain ceramics manufacturing processes that exceed a minimum production level (i.e., annually consume at least 2,000 tons of carbonates, either as raw materials or as a constituent in clay, heated to a temperature sufficient to allow the calcination reaction to occur) and that exceed the 25,000 mtCO2e threshold. The revisions to tables A–3 and A–4 to subpart A clarify that these new source categories apply in RY2025 and future years. The EPA is finalizing several revisions to defined terms in 40 CFR 98.6 as proposed to provide further clarity. These revisions to definitions include: • Revising the definition of ‘‘bulk’’ to clarify that the import and export of gas includes small containers and does not exclude a minimum container size below which reporting will not be required (except for small shipments (i.e., those including less than 25 kilograms)), and to align with the definition of ‘‘bulk’’ under the American Innovation and Manufacturing Act of 2020 (AIM) regulations at 40 CFR part 84. • Revising the definition of ‘‘greenhouse gas or GHG’’ to clarify the treatment of fluorinated greenhouse gases by removing the partial list of fluorinated GHGs currently included in the definition and to simply refer to the definition of ‘‘fluorinated greenhouse gas (GHG).’’ PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 • Adding the acronym ‘‘(GHGs)’’ after the term ‘‘fluorinated greenhouse gas’’ both in the definition of ‘‘greenhouse gas or GHG’’ and in the definition of ‘‘fluorinated greenhouse gas’’ to avoid redundancy and potential confusion between the definitions of ‘‘greenhouse gas’’ and ‘‘fluorinated greenhouse gas.’’ • Consistent with the revisions of the fluorinated GHG groups used to assign default GWPs discussed in section III.A.1.a. of this preamble, adding a definition of ‘‘cyclic’’ as it applies to molecular structures of various fluorinated GHGs; adding definitions of ‘‘unsaturated chlorofluorocarbons (CFCs),’’ ‘‘saturated chlorofluorocarbons (CFCs),’’ ‘‘unsaturated bromofluorocarbons (BFCs),’’ ‘‘unsaturated bromochlorofluorocarbons (BCFCs),’’ ‘‘unsaturated hydrobromofluorocarbons (HBFCs),’’ and ‘‘unsaturated hydrobromochlorofluorocarbons (HBCFCs)’’; and revising the definition of ‘‘fluorinated greenhouse (GHG) group’’ to include the new and revised groups. • Revising the term ‘‘other fluorinated GHGs’’ to ‘‘remaining fluorinated GHGs’’ and to revise the definition of the term to reflect the new and revised fluorinated GHG groups discussed in section III.A.1.a. of this preamble. • Revising the definition of ‘‘fluorinated heat transfer fluids’’ and moving it from 40 CFR 98.98 to 98.6 to harmonize with changes to subpart OO of part 98 (Suppliers of Industrial Greenhouse Gases) (see section III.U. of this preamble). The revised definition (1) explicitly includes industries other than electronics manufacturing, and (2) excludes most HFCs which are widely used as heat transfer fluids outside of electronics manufacturing and are regulated under the AIM regulations at 40 CFR part 84. • Consistent with final revisions to subpart PP (Suppliers of Carbon Dioxide) (see section III.V. of this preamble), we are finalizing revisions to 40 CFR 98.6 to add a definition for ‘‘Direct air capture’’ and to amend the definition of ‘‘Carbon dioxide stream.’’ The EPA is making one revision to the definitions in the final rule from proposed to correct the definition of ‘‘ASTM’’. This change updates the definition to include the current name of the standards organization, ‘‘ASTM, International’’. Consistent with final revisions to subparts Q (Iron and Steel Production), VV (Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916), WW (Coke Calciners), and XX (Calcium Carbide Production), we are finalizing revisions to 40 CFR E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 98.7 to incorporate by reference ASTM International (ASTM) E415–17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (2017) (subpart Q); CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation and geological storage—Carbon dioxide storage using enhanced oil recovery (CO2–EOR) (2019) (subpart VV) (as proposed in the 2023 Supplemental Proposal); ASTM D3176–15 Standard Practice for Ultimate Analysis of Coal and Coke (2015), ASTM D5291–16 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (2016), ASTM D5373–21 Standard Test Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke (2021), and NIST HB 44– 2023: Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, 2023 edition (subpart WW); and ASTM D5373–08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (2008) and ASTM C25– 06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (2006) (subpart XX). The EPA has revised the regulatory text of 40 CFR 98.7 from proposal to incorporate these revisions and to reorganize the existing referenced ASTM standards in alphanumeric order. The EPA is not finalizing proposed amendments to subpart A from the 2022 Data Quality Improvements Proposal that correlate with proposed amendments to subpart W of part 98 (Petroleum and Natural Gas Systems) from the 2022 Data Quality Improvements Proposal in this action. As noted in section I.C. of this preamble, the EPA has issued a subsequent proposed rule for subpart W on August 1, 2023, and has reproposed related amendments to subpart A in that action. Additionally, the EPA is not taking final action at this time on proposed amendments to subpart A from the 2023 Supplemental Proposal that were proposed harmonizing revisions intended to integrate proposed subpart B (Energy Consumption), including proposed reporting and recordkeeping under 40 CFR 98.2(a)(1), 98.3(c)(4), and 98.3(g)(5). Finally, we are not taking final action, at this time, on proposed amendments to 40 CFR 98.7 to incorporate by reference standards for electric metering. As discussed in section III.B. of this document, the EPA VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 is not taking final action on subpart B at this time. c. Revisions To Streamline and Improve Implementation for Subpart A The EPA is finalizing several revisions to subpart A proposed in the 2022 Data Quality Improvements Proposal that will streamline and improve implementation for part 98. First, we are revising tables A–3 and table A–4 to subpart A to revise the applicability of subparts DD (Electrical Transmission and Distribution Equipment Use) and SS (Electrical Equipment Manufacture of Refurbishment) of part 98 as proposed. For subpart DD, the final revisions to table A–3 change the threshold such that facilities must account for the total estimated emissions from F–GHGs, as determined under 40 CFR 98.301 (subpart DD), for comparison to a threshold equivalent to 25,000 mtCO2e or more per year. We are also moving subpart SS from table A–3 to table A– 4 to subpart A and specifying that subpart SS facilities must account for emissions of F–GHGs, as determined under the requirements of 40 CFR 98.451 (subpart SS), for comparison to a threshold equivalent to 25,000 mtCO2e or more per year. The final rule updates the threshold of subparts DD and SS to be consistent with the threshold set for the majority of subparts under part 98, and accounts for additional fluorinated gases (including F–GHG mixtures) reported by industry. For subpart DD, these final changes also focus Agency resources on the substantial emission sources within the sector by excluding facilities or operations that may report emissions that are consistently and substantially below 25,000 mtCO2e per year. See sections III.Q. and III.Y. of this preamble for additional information. 2. Summary of Comments and Responses on Subpart A This section summarizes the major comments and responses related to the proposed amendments to subpart A. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart A. a. Comments on Revisions To Global Warming Potentials Comment: Several commenters supported the proposed revisions to table A–1 to subpart A to update the GWP values to use values from table PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 31817 8.A.1 from the IPCC AR5, and for certain GHGs without GWP values listed in AR5, to adopt values from the IPCC AR6. Commenters remarked that the updates to the GWP values will be more accurate, align with UNFCCC guidance and the Inventory, and provide consistency to reporters who may also report under various voluntary standards, such as the GHG Protocol or Sustainability Accounting Standards Board. Some commenters requested that the EPA clarify the effects of changing the GWP (particularly for CH4) on the reported total CO2e emissions, despite any actual change in mass emissions. The commenters asserted that it is important to inform stakeholders that future increases in CO2e emissions due to the change in GWP are not reflective of any actual mass emission increases and may obscure decreases in annual mass emissions. The commenters also recommended that the EPA acknowledge how combustion CO2e emissions will be affected. Response: In the final rule, the EPA is finalizing its proposal (in the 2023 Supplemental Proposal) to adopt the 100-year GWPs from AR5, and for certain GHGs without GWPs listed in AR5, to adopt values from AR6. Regarding the commenters’ concern that the change in GWPs may result in apparent, but not real, upward or downward trends in the data, the EPA has always published emissions using consistent GWPs for every year and will continue to do so. Prior to publication, the EPA updates all reported CO2e values to reflect the current GWP values in table A–1 to subpart A of part 98. The CO2e published by the EPA are based on the same GWP values across all reporting years. Hence, there will be no apparent upward or downward trend in emissions that are due only to a change in a GWP value. Comment: A number of commenters supported the continued use of a 100year GWP; one commenter stated that the 100-year GWP is consistent with Article 2 of the UNFCCC and that any movement to a framework that reduces the mitigation focus on CO2 emissions and adds to long-term warming potential compared to the 100-year GWP framework would not be well justified. Several commenters specifically commented on the proposed GWP for CH4; a number of commenters generally supported revising the CH4 GWP value from 25 to 28 using the 100-year GWP. Other commenters recommended that the EPA consider incorporating GWP values on multiple time horizons in the reporting requirement, or when publicizing reported emissions. One E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31818 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations commenter stated that the 100-year GWP does not capture the near-term potency of short-lived gases like methane and hydrogen and is insufficient to reflect a pollutant’s warming power over time. Commenters requested that the EPA incorporate the use of additional time horizons, such as the 20-year GWP, to acknowledge the near-term warming potency of shortlived gases such as CH4, because they play a critical role in driving the rate of warming for the near future. Commenters argued that the 20-year GWP more accurately represents the powerful, short-term impact of methane on the atmosphere. Commenters noted that this would also align with several state regulatory programs, including California, New York, and New Jersey, that currently consider 20-year GWPs. Commenters stressed that adopting short-lived climate pollutant strategies and emissions controls to limit nearterm warming is critical from a policy perspective and directly relevant to the EPA’s efforts under the Clean Air Act. Commenters also requested that historic inventories be updated to reflect the role that short-lived climate pollutants play and to demonstrate that near-term CH4 emissions reductions are as important as long-term CO2 reductions. Response: As has been the case since the inception of the GHGRP, we are finalizing 100-year GWPs for all GHGs. As noted in the ‘‘Response to Comments on Final Rule, Volume 3: General Monitoring Approach, the Need for Detailed Reporting, and Other General Rationale Comments’’ (see Docket ID. No. EPA–HQ–OAR–2008–0508–2260), the EPA selected the 100-year GWPs because these values are the internationally accepted standard for reporting GHG emissions. For example, the parties to the UNFCCC agreed to use GWPs that are based on a 100-year time period for preparing national inventories, and the reports submitted by other signatories to the UNFCCC use GWPs based on a 100-year time period, including the GWP for CH4 and certain GHGs identified as short-lived climate pollutants. These values were subsequently adopted and used in multiple EPA climate initiatives, including the EPA’s Significant New Alternatives Policy (SNAP) program and the Inventory, as well as EPA voluntary reduction partnerships (e.g., Natural Gas STAR). Human-influenced climate change occurs on both short (decadal) and long (millennial) time scales. While there is no single best way to value both short- and long-term impacts in a single metric, the 100-year GWP is a reasonable approach that has been VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 widely accepted by the international community. If the EPA were to adopt a 20-year GWP solely for CH4, or for certain other compounds, it would introduce a metric that is inconsistent with both the GWPs used for the remaining table A–1 gases and with the reporting guidelines issued by the UNFCCC and used by the Inventory and other EPA programs. Additionally, the EPA and other Federal agencies, which calculate the impact of short-lived GHGs using 100-year GWPs, are making reduction of short-lived GHGs a priority, such as through the U.S. Global Methane Initiative. In addition, it is beneficial for both regulatory agencies and industry to use the same GWP values for these GHG compounds because it allows for more efficient review of data collected through the GHGRP and other U.S. climate programs, reduces potential errors that may arise when comparing multiple data sets or converting GHG emissions or supply based on separate GWPs, and reduces the burden for reporters and agencies to keep track of separate GWPs. For the reasons described above, the EPA is retaining a 100-year time horizon as the standard metric for defining GWPs in the GHGRP. b. Comments on Other Revisions To Improve the Quality of Data Collected for Subpart A Comment: Several commenters opposed the EPA’s proposed revisions to 40 CFR 98.3(h)(4) to limit the total number of days a reporter can request to extend the time period for resolving a substantive error, either by submitting a revised report or providing information demonstrating that the previously submitted report does not contain the substantive error, to 180 days. Commenters requested that the Agency not put an inflexible cap on the number of days to resolve reporting issues; the commenters asserted that the extensions can be helpful for newly affected sources, when there is a change in facility ownership, and in other situations. One commenter stated that the proposed revision may result in arbitrarily short time-periods in which an operator may correct an error, especially in cases where the correction may not be accepted. The commenter contended that the EPA must add additional language to clarify that the 180-day limit will restart if the correction is not accepted. Commenters also requested that the EPA increase the limit of the total number of days a reporter can request an extension beyond the proposed 180 days to provide reporters more time to work through the new provisions in the PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 program. One commenter requested the EPA restart the 180-day extension request opportunity for each instance in which an operator is notified of a substantive error or rejected correction (e.g., if a correction is rejected, if additional corrections are requested, if corrections span more than one reporting year, or if EPA responses to operator questions are delayed). Response: The EPA expects that 180 days is a reasonable amount of time for a facility to examine company records, gather additional data, and/or perform recalculations to submit a revised report or provide the necessary information such that the report may be verified. This represents more than four 30-day additional extensions beyond the initial 45-day period. As noted in the preamble to the final rule promulgated on October 30, 2009 (74 FR 52620, hereafter referred to as the ‘‘2009 Final Rule’’), the EPA concluded that this initial 45day period would be sufficient since facilities have three months from the end of a reporting period to submit the initial annual report and have already collected and retained data needed for the analyses, so revisions to address a known error would likely require less time (see 74 FR 56278). A subsequent series of extensions of up to an additional 135 days is a reasonable amount of time to accommodate any additional changes that may be needed to the revision. B. Subpart B—Energy Consumption The EPA is not taking final action on the proposed addition of subpart B of part 98 (Energy Consumption) in this final rule. The EPA received a number of comments for proposed subpart B. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to proposed subpart B. In the 2022 Data Quality Improvements Proposal, the EPA requested comment on collecting data on energy consumption in order to improve the quality of the data collected under the GHGRP. Specifically, we provided background on the EPA’s original request for comment on the collection of data related to electricity consumption in the development of part 98 and the EPA’s response in the 2009 Final Rule, and requested comment on whether and how the EPA should collect energy consumption data in order to support data analyses related to informing voluntary energy efficiency E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations programs, provide information on industrial sectors where currently little data are reported to GHGRP, and inform quality assurance/quality control (QA/ QC) of the Inventory. We requested comment on specific considerations for the potential addition of the energy consumption source category (see section IV.F. of the preamble to the 2022 Data Quality Improvements Proposal for additional information). Following consideration of comments received in response to the EPA’s request for comment, we subsequently proposed, in the 2023 Supplemental Proposal, the addition of subpart B to part 98. At that time, we reiterated our interest in collecting data on energy consumption to gain an improved understanding of the energy intensity (i.e., the amount of energy required to produce a given level of product or activity, both through on-site energy produced from fuel combustion and purchased energy) of specific facilities or sectors, and to better inform our understanding of energy needs and the potential indirect GHG emissions associated with certain sectors. The proposed rule included specific monitoring and reporting requirements for direct emitting facilities that report under part 98 and purchase metered electricity or metered thermal energy products. In the proposed rule, the EPA outlined a source category definition, rationale for the proposed applicability of the subpart to direct emitting facilities in lieu of a threshold, and specific monitoring, missing data, recordkeeping, and reporting requirements. The EPA did not propose requirements for facilities to calculate or report indirect emissions estimates associated with purchased metered electricity or metered thermal energy products. Additional information on the proposed amendments is available in the preamble to the 2023 Supplemental Proposal. In response to the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, the EPA received many comments on the proposed subpart from a variety of stakeholders providing input on the definition, applicability criteria, monitoring, reporting, recordkeeping, and additional requirements of the source category, as proposed, as well as a number of comments on the EPA’s authority to collect the energy consumption data proposed under subpart B. The EPA is not taking final action on proposed subpart B at this time. The EPA intends to further review and consider these comments and other relevant information and may consider any next steps on the collection of data VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 related to energy consumption in a future rulemaking. Therefore, none of the proposed requirements related to subpart B are included in this final rule. The EPA is also not taking final action on related amendments to subpart A (General Provisions) of part 98 that were proposed harmonizing changes for the implementation subpart B, including reporting requirements, as discussed in section III.A.1.b. of this preamble. C. Subpart C—General Stationary Fuel Combustion The EPA is finalizing several amendments to subpart C of part 98 (General Stationary Fuel Combustion) as proposed. In some cases, we are finalizing the proposed amendments with revisions. In other cases, we are not taking final action on the proposed amendments. Section III.C.1. of this preamble discusses the final revisions to subpart C. The EPA received several comments on the proposed subpart C revisions which are discussed in section III.C.2. of this preamble. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the final revisions to subpart C, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart C This section summarizes the final amendments to subpart C. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart C can be found in this section and section III.C.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Revisions To Improve the Quality of Data Collected for Subpart C The EPA is finalizing several revisions to improve the quality of data collected for subpart C. First, the EPA is finalizing modifications to the Tier 3 calculation methodology, including revisions to 40 CFR 98.33(a)(3)(iii) to provide new equations C–5A and C–5B, as proposed. The updated equations provide for calculating a weighted annual average carbon content and a weighted annual average molecular weight, respectively, and correct the calculation method for Tier 3 gaseous fuels. The new equations incorporate the molar volume conversion factor at standard conditions (as defined at 40 CFR 98.6) and, for annual average carbon content, the measured molecular PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 31819 weight of the fuel, in order to convert the fuel flow to the appropriate units of measure. The final rule includes corrections to the proposed paragraph references included in the definition of the variable ‘‘MW’’ (i.e., molecular weight) to equation C–5. The EPA is also finalizing as proposed revisions to provisions pertaining to the calculation of biogenic emissions from tire combustion. These revisions include: • Removing the additional provision in 40 CFR 98.33(b)(1)(vii) on how to apply the threshold to only municipal solid waste (MSW) fuel when MSW and tires are both combusted and the reporter elects not to separately calculate and report biogenic CO2 emissions from the combustion of tires, since biogenic CO2 emissions from tire combustion must now be calculated and reported in all cases; • Removing the language in 40 CFR 98.33(e) and 98.36(e)(2)(xi) referring to optional biogenic CO2 emissions reporting from tire combustion; • Removing the restriction in 40 CFR 98.33(e)(3)(iv) that the default factor that is used to determine biogenic CO2 emissions may only be used to estimate the annual biogenic CO2 emissions from the combustion of tires if the combustion of tires represents ‘‘no more than 10 percent annual heat input to a unit’’; • Revising 40 CFR 98.33(e)(3)(iv)(A) so that total annual CO2 emissions will be calculated using the applicable methodology in 40 CFR 98.33(a)(1) through (3) for units using Tier 1 through 3 for purposes of 40 CFR 98.33(a), and using the Tier 1 calculation methodology in 40 CFR 98.33(a)(1) for units using the Tier 4 or part 75 calculation methodologies for purposes of 40 CFR 98.33(a), when determining the biogenic component of MSW and/or tires under 40 CFR 98.33(e)(3)(iv); • Revising 40 CFR 98.33(e)(3)(iv)(B) to update the default factor that is used to determine biogenic CO2 emissions from the combustion of tires from 0.20 to 0.24; and • Correcting 40 CFR 98.34(d) to reference 40 CFR 98.33(e)(3)(iv) instead of 40 CFR 98.33(b)(1)(vi) and (vii) and correcting 40 CFR 98.33(e)(1) to delete the parenthetical clause ‘‘(except MSW and tires).’’ These final revisions will update the default factor to be based on more recent data collected on the average composition of natural rubber in tires, remove potentially confusing or conflicting requirements, and result in a more accurate characterization of biogenic emissions from these sources. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31820 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations See section III.B.1. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. The EPA is also finalizing one additional revision related to the estimation of biogenic emissions after consideration of comments received on the 2022 Data Quality Improvements Proposal. Commenters requested that the EPA expand the monitoring requirements at 40 CFR 98.34(e) to include all combined biomass and fossil fuels and to allow for testing at one source when a common fuel is combusted. The EPA agrees that testing one emission source is reasonable when multiple combustion units are fed from a common fuel source. Accordingly, the EPA is revising 40 CFR 98.34(e) to allow for quarterly ASTM D6866–16 and ASTM D7459–08 testing of one representative unit for a common fuel source for all combined biomass (or fuels with a biomass component) and fossil fuels. See section III.C.2. of this preamble for additional information on related comments and the EPA’s response. We are finalizing corrections to the variable ‘‘R’’ in equation C–11. The term ‘‘R’’ is currently defined as ‘‘The number of moles of CO2 released upon capture of one mole of the acid gas species being removed (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas species is SO2)’’ and is being amended to ‘‘The number of moles of CO2 released per mole of sorbent used (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas species is SO2).’’ We are finalizing amendments to 40 CFR 98.33(c)(6)(i), (ii), (ii)(A), and (iii)(C), and to remove and reserve 40 CFR 98.33(c)(6)(iii)(B) (to clarify the methods used to calculate CH4 and N2O emissions for blended fuels when heat input is determined after the fuels are mixed and combusted), as proposed. The EPA identified one additional minor correction to subpart C in review of changes for the final rule. Subsequently, we are correcting the definition of the term emission factor ‘‘EF’’ in equation C–10 from ‘‘Fuelspecific emission factor for CH4 or N2O, from table C–2 of this section’’ to ‘‘Fuelspecific emission factor for CH4 or N2O, from table C–2 to this subpart.’’ The EPA is finalizing as proposed two additional clarifications to the reporting and recordkeeping requirements. We are revising the first sentence of 40 CFR 98.36(e)(2)(ii)(C) to clarify that both the annual average, and where applicable, monthly high heat values are required to be reported. This change clarifies that the annual average high heat value is also a reporting requirement (for VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 reporters who do not use the electronic inputs verification tool (IVT) within the e-GGRT). We are finalizing revisions to the 40 CFR 98.37(b) introductory paragraph and paragraphs (b)(9) through (11), (14), (18), (20), (22), and (23) to specify recordkeeping data that is currently contained in the file generated by the verification software that is already required to be retained by reporters under 40 CFR 98.37(b). These revisions correct omissions that currently exist in the verification software recordkeeping requirements specific to equations C–2a, C–2b, C–3, C–4, and C–5. They also align the verification software recordkeeping requirements with the final revisions to equation C–5 at 40 CFR 98.33(a)(3)(iii). In the 2022 Data Quality Improvements Proposal, we proposed additional reporting requirements, for each unit greater than or equal to 10 mmBtu/hour in either an aggregation of units or common pipe configuration. The proposed reporting included, for each individual unit with maximum rated heat input capacity greater than or equal to 10 mmBtu/hour included in the group, the unit type, maximum rated heat input capacity, and an estimate of the fraction of the total group annual heat input attributable to each unit (proposed 40 CFR 98.36(c)(1)(ii) and (c)(3)(xi)). Following consideration of public comments, the EPA is not taking final action on the proposed reporting requirements (i.e., identifying the unit type, maximum rated heat input capacity, and fraction of the total annual heat input for each unit in the aggregation of unit or common pipe). See section III.C.2. of this preamble for a summary of the related comments and the EPA’s response. In the 2023 Supplemental Proposal, the EPA proposed to add a requirement to report whether the unit is an EGU for each configuration that reports emissions, under either the individual unit provisions at 40 CFR 98.36(b)(12) or the multi-unit provisions at 40 CFR 98.36(c)(1)(xii), (c)(2)(xii), and (c)(3)(xii). For multi-unit reporting configurations, we also proposed adding a requirement for facilities to report an estimated decimal fraction of total emissions from the group that are attributable to EGU(s) included in the group. Following consideration of public comments, the EPA is not taking final action on the proposed revisions to the reporting requirements in this rule. See section III.C.2. of this preamble for a summary of the related comments and the EPA’s response. The EPA is also not taking final action in this final rule on proposed revisions to subpart C correlated with proposed PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 amendments to subpart W (Petroleum and Natural Gas Systems). As noted in section I.C. of this preamble, the EPA has issued a subsequent proposed rule for subpart W on August 1, 2023 and has reproposed related amendments to subpart C in that separate action. b. Revisions To Streamline and Improve Implementation for Subpart C The EPA is finalizing all revisions to streamline and improvement implementation for subpart C as proposed. Specifically, the EPA is finalizing (1) amendments to 40 CFR 98.34(c)(6) to allow cylinder gas audits (CGAs) to be performed using calibration gas concentrations of 40–60 percent and 80–100 percent of CO2 span, whenever the required CO2 span value for a flue gas does is not appropriate for the prescribed audit ranges in appendix F of 40 CFR part 60; and (2) amendments to provisions in 40 CFR 98.36(c)(1)(vi) and 98.36(c)(3)(vi) to remove language requiring that facilities with the aggregation of units or common pipe configuration types report the total annual CO2 mass emissions from all fossil fuels combined. See section III.B.2. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these changes and their supporting basis. 2. Summary of Comments and Responses on Subpart C This section summarizes the major comments and responses related to the proposed amendments to subpart C. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart C. Comment: One commenter provided a correction to the proposed revisions to equation C–5 related to the revisions to the Tier 3 calculation methodology. The commenter noted that the proposed revisions to variable ‘‘MW’’ of equation C–5 which specify the procedures to be used to determine the annual average molecular weight included an incorrect reference to paragraphs (a)(3)(iii)(A)(3) and (4), and should point to (a)(3)(iii)(B)(1) and (2). Response: We agree that the proposal inadvertently contained incorrect crossreferences for the variable ‘‘MW’’ of equation C–5, and the EPA has corrected these cross-references in the final rule. Comment: Commenters generally supported the EPA’s proposed revisions E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations to update the calculation methodology for biogenic emissions from tire combustion. One commenter requested that the EPA consider expanding the requirements of 40 CFR 98.34(e), which requires quarterly testing to determine biogenic CO2 when biomass and nonbiogenic fuels are co-fired in a unit. The commenter noted that 40 CFR 98.34(e) currently allows for testing of a single representative unit for facilities with multiple units in which tires are the primary fuel combusted and the units are fed from a common fuel source. The commenter noted that for facilities with multiple units combusting the same fuel, testing each source quarterly imposes an additional burden without enhancing the accuracy of reported emissions. The commenter requested that the EPA expand the provisions to include all combined biomass and fossil fuels and to allow for testing one representative unit when fuel from a common fuel source is combusted. Response: The EPA acknowledges the commenter’s support for the proposed revisions. The EPA agrees with the commenter that testing one emission source when multiple emission sources are fed from a common fuel source should be allowed for all combined biomass (or fuels with a biomass component) and fossil fuels. Accordingly, the EPA has finalized quarterly ASTM D6866–16 and ASTM D7459–08 testing of one representative unit for multiple units fed from a common fuel source, for all combined biomass (or fuels with a biomass component) and fossil fuels. Comment: Some commenters supported the EPA’s proposal to revise 40 CFR 98.36(c)(1) and (3) to require reporting of additional information for each unit in either an aggregation of units or common pipe configuration (excluding units with maximum rated heat input capacity less than 10 mmBtu/ hour), including the unit type, maximum rated heat input capacity, and an estimate of the fraction of the total annual heat input to the unit. These commenters agreed that unit-specific data is necessary to understand both the distribution of emissions across unit types and sizes, but also the abatement potential through various decarbonization strategies (e.g., certain abatement strategies may be better suited for certain unit types and uses). The commenters stated that the requested data could assist the EPA in the development of NSPS or EG under CAA section 111. The commenters noted that, given the prevalence of reporting using combined configurations, this data would fill large data gaps in the current characterization VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 of industrial sectors. One commenter asserted that the requirement should be extended to facilities that report using the common stack configuration or the alternative part 75 configuration, which would ensure that all emissions under the subpart are similarly affected by the proposed revisions and would provide a full picture of the GHG abatement potential of various source categories. Commenters also requested the EPA consider lowering or eliminate the size threshold below 10 mmBtu/hour; the commenter stated that although smaller units do not account for a large share of total capacity, they often present the most viable opportunities for greenhouse gas emissions abatement such as electrification with heat pump technology. Other commenters opposed the proposed requirements. Opposing commenters stated that the EPA’s explanation for collecting the data was ambiguous and did not sufficiently explain what data gaps are missing or how the collection of the additional information would resolve issues within the currently collected data. One commenter opposed disaggregating total emissions from the grouped combustion equipment, asserting that aggregating the emissions by individual equipment (excluding units rated less than 10 mmBtu/hour) using estimation techniques would not provide useful information. Several commenters asserted that the proposed approach could not reliably provide accurate estimates of actual heat input and is likely not to be technically feasible. For example, one commenter stated that the physical configuration of certain lime plants would preclude accurate unitspecific estimates of actual heat input, as the facilities lack certified calibrated meters on a kiln-by-kiln basis and rely on quantifying solid fuel usage based on surveys of on-site stockpiles. The commenter added that facility-wide reporting of combustion emissions satisfies the EPA’s objective of developing facility-wide emissions information, and additional unit-level information is superfluous and of limited value. Other commenters stated that individual fuel meters are not common, asserting that annual heat input for individual units is often estimated based on the maximum high heat input rating and operating hours. One commenter stated that the heat input records maintained by facilities do not necessarily correspond to the actual heat input of a unit, especially for industries that use batching with different process equipment for different products. That commenter asserted that PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 31821 actual heat input may vary based on age of the unit; how it is utilized in processes for steam, cooling, or other purposes; and the high heating value of fuel during certain operating periods. Another commenter questioned whether the estimation technique proposed would likely undermine the reported data or compromise the integrity of actual values that are currently reported. Commenters asserted that the requirements would have potentially very limited value and may detract from the GHG emission estimates that regulated facilities produce for the EPA or other proposed Federal rules. Commenters also expressed that the proposed requirements would be overly burdensome and significantly increase the recordkeeping and reporting burden. One commenter specifically referred to the requirement for facilities to estimate the total annual input of each unit expressed as a decimal fraction based on the actual heat input of each unit compared to the whole; the commenter stated that this requirement would essentially negate the time efficiencies gained by reporting the aggregated group, especially for reporters using the common pipe configuration. The commenter stated that this would essentially require that heat inputs be calculated for each piece of equipment each year and could result in a ten-fold increase in burden for reporters using the common pipe method. Commenters urged that the maximum rated heat input of each unit in the aggregated group and operating hours should provide enough information for the EPA to reasonably approximate emissions for individual equipment. Response: Upon careful consideration, the EPA has decided not to take final action on the proposed reporting requirements for each unit greater than or equal to 10 mmBtu/hour in either an aggregation of units or common pipe configuration (the unit type, maximum rated heat input capacity, and an estimate of the fraction of the total annual heat input attributable to each unit in the group) (proposed 40 CFR 98.36(c)(1)(ii) and (c)(3)(xi)) at this time. We note that the EPA disagrees that estimating the fraction of the actual total annual heat input for each unit in the group, based on company records, will be overly burdensome to reporters. ‘‘Company records’’ is defined in the existing part 98 regulations at 40 CFR 98.6 to mean, ‘‘in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31822 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations usage. Company records may include, but are not limited to, direct measurements of fuel consumption by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.’’ The broad definition of company records would afford reporters considerable flexibility when it comes to estimating the fraction of the actual total annual heat input for each unit in the group. The EPA may consider such reporting requirements in future rulemakings. Comment: Two commenters stated that EGUs should not be reported under subpart C and are already reported under subpart D (Electricity Generation); one commenter asserted that it is unclear from the proposal how reporting these emissions under subpart C would not be duplicative. One of the two commenters additionally stated that EGUs are not specifically defined in subparts A or C of part 98, and that the EPA should provide clarification on the definition of EGUs. The commenter added that the proposed requirement would impose burden and regulatory confusion because of the conflicting definitions in, and applicability of, other EPA regulatory programs which traditionally have regulated EGUs separately from non-EGU combustion sources. The commenter stated that 40 CFR 98.36(f) already requires sources to identify if they are tied to an entity regulated by any public utility commission. Another commenter suggested a definition for EGUs that aligns with a footnote to table A–7 to subpart A that defines EGUs for sources reporting under subpart C as ‘‘a fuel-fired electric generator owned or operated by an entity that is subject to regulation of customer billing rates by the public utilities commission (excluding generators connected to combustion units subject to 40 CFR part 98, subpart D) and that are located at a facility for which the sum of the nameplate capacities for all such electric generators is greater than or equal to 1 megawatt electric output.’’ One commenter requested clarification that waste heat generation is not included; the commenter added that requiring facilities to report emissions from the generation of electricity using waste heat recovery would be double counting. Other commenters requested clarification that emergency generators are exempt from the proposed requirements. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Two commenters supported the EPA’s proposed requirement to allow operators to use an engineering estimate of the percentage of combustion emissions attributable to facility electricity generation. However, another commenter disagreed, stating that the EPA did not describe how a reporter would identify such a fraction. The commenter added that the EPA failed to take into account that emissions from a single combustion unit might provide steam to multiple consumers for multiple purposes, only a portion of which includes on-site electricity generation. The commenter expressed concerns that, if the rule is finalized as proposed, the methods to determine electricity-related emissions by fraction could become subject to numerous other requirements, such as calculations for GHG emissions, monitoring and QA/QC requirements, data reporting, and record retention obligations. Response: The EPA is not taking final action on the proposed addition of a new indicator that would identify units as electricity generating units at this time. Furthermore, the EPA is not taking final action on the additional requirement for reporting an estimate of a group’s total reported emissions attributable to electricity generation at this time. As discussed in the preamble to the 2023 Supplemental Proposal, under the current subpart C reporting requirements, the EPA cannot currently determine the quantity of EGU emissions included in the reported total emissions for the subpart. Although some facilities currently indicate whether certain stationary fuel combustion sources are connected to a fuel-fired electric generator in 40 CFR 98.36(f), this requirement only captures a subset of subpart C EGU emissions. The EPA therefore intended the proposed reporting requirements to identify other EGUs reporting under subpart C in order to improve our understanding of subpart C EGU GHG emissions and the attribution of GHG emissions to the power plant sector. However, we agree with commenters that the proposed requirements could require additional burden not contemplated by the proposed rule. Specifically, as noted by commenters, we recognize that there could be scenarios in which a single combustion unit or group of units may provide steam for multiple purposes, only a portion of which includes on-site electricity generation. In this case, although a facility may know the quantity of electricity generated and could estimate the quantity of steam required to generate the electricity, PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 determination of the portion of GHG emissions that are attributable to the combustion unit(s) producing the steam that is used in an on-site EGU (among other processes) would additionally require the estimation of the type and quantity of fuel used by each combustion unit for the purposes of producing the steam used to generate electricity. For this reason we are not taking final action on these requirements in this rule. D. Subpart F—Aluminum Production We are not taking final action on any proposed amendments to subpart F of part 98 (Aluminum Production) in this action. In the 2022 Data Quality Improvements Proposal, the EPA requested comment on several issues related to determining emissions from aluminum production. Specifically, the EPA requested information on the extent to which low voltage emissions have been characterized, if data are available to develop guidance on low voltage emission measurements, and on the use of the non-linear method as an alternative to the slope coefficient and overvoltage methods currently allowed in subpart F. The EPA received comments on these issues but is not taking final action on any changes to the measurement methodology for subpart F at this time. In the 2023 Supplemental Proposal, the EPA proposed revisions to the reporting requirements at 40 CFR 98.66(a) and (g) to require that facilities report the facility’s annual production capacity and annual days of operation for each potline. We noted at that time that the capacity of the facility and capacity utilization would provide useful information for understanding variations in annual emissions and emission trends across the sector. The EPA received several comments on the proposed subpart F revisions. Following consideration of comments received, we are not taking final action on the proposed revisions at this time. However, the EPA may consider similar changes to reporting requirements in a future rulemaking. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA– HQ–OAR–2019–0424 for a complete listing of all comments and responses related to subpart F. E. Subpart G—Ammonia Manufacturing We are finalizing amendments to subpart G of part 98 (Ammonia Manufacturing) as proposed. In some cases, we are finalizing the proposed E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations amendments with revisions. In other cases, we are not taking final action on the proposed amendments. This section discusses the final revisions to subpart G. The EPA received only supportive comments for the proposed revisions to subpart G. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA– HQ–OAR–2019–0424 for a complete listing of all comments and responses related to subpart G. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. In the 2022 Data Quality Improvements Proposal, the EPA proposed several revisions to subpart G to require reporters to report the GHG emissions that occur directly from the ammonia manufacturing process (i.e., net CO2 process emissions) after subtracting out carbon or CO2 captured and used in other products. The proposed revisions included combining equation G–4 and equation G–5 into a new equation G–4 and several harmonizing revisions to 40 CFR 98.72(a); revisions to the introductory paragraph of 40 CFR 98.73; the removal of § 98.73(b)(5); revisions to the introductory paragraph of 40 CFR 98.76; and revisions to the reported data elements at 40 CFR 98.76(b)(1) and (13), as described in section III.C. of the preamble to the 2022 Data Quality Improvements Proposal. The EPA is finalizing minor edits to 40 CFR 98.72(a), the introductory paragraph of 40 CFR 98.73, the introductory paragraph to 40 CFR 98.76, and 40 CFR 98.76(b)(1) to clarify the term ‘‘ammonia manufacturing unit,’’ as well as clarifying edits to 40 CFR 98.76(b)(13) to clearly identify any CO2 used in the production of urea and carbon bound in methanol that is intentionally produced as a desired product. Additionally, we are finalizing clarifying amendments to equation G–1, equation G–2, and equation G–3 to simplify the equations by removing the process unit ‘‘k’’ designation in the terms ‘‘CO2,G,k,’’ ‘‘CO2,L,k,’’ and ‘‘CO2,S,k.’’ We are also finalizing the removal of § 98.73(b)(5) and equation G– 5, consistent with our intent at proposal to require reporting of emissions by ammonia manufacturing unit. Following consideration of comments received on similar changes proposed for subpart S (Lime Manufacturing), the EPA is not taking final action at this time on the proposed revisions to allow facilities to subtract out carbon or CO2 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 captured and used in other products. We have revised new equation G–4 in the final rule to remove the proposed equation terms related to CO2 collected and consumed on-site for urea production and the mass of methanol intentionally produced as a desired product, and removed text related to ‘‘net’’ CO2 process emissions. The EPA is also not taking final action at this time on the addition of related monthly recordkeeping data elements that were proposed as verification software records. See section III.K.2. of this preamble for a summary of related comments and the EPA’s response. We are finalizing as proposed one amendment to subpart G from the 2023 Supplemental Proposal to include a requirement for facilities to report the annual quantity of excess hydrogen produced that is not consumed through the production of ammonia at 40 CFR 98.76(b)(16). This is a harmonizing change to ensure that the final revisions to subpart P (Hydrogen Production) to exclude reporting from any process unit for which emissions are reported under another subpart of part 98, including ammonia production units that report emissions under subpart G (see section III.I. of this preamble), will not result in the exclusion of reporting of any excess hydrogen production at facilities that are subject to subpart G. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart G, as described in section VI. of this preamble. F. Subpart H—Cement Production We are finalizing several amendments to subpart H of part 98 (Cement Production) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.F.1. of this preamble discusses the final revisions to subpart H. The EPA received several comments on the proposed subpart H revisions which are discussed in section III.F.2. of this preamble. We are also finalizing confidentiality determinations for new data elements resulting from the revisions to subpart H, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart H This section summarizes the final amendments to subpart H. Major changes in this final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart H can be found in this section and section III.F.2. of this preamble. Additional rationale for these PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 31823 amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. The EPA is finalizing several revisions to improve the quality of data collected for subpart H. First, we are finalizing the addition of several new data reporting elements to subpart H under 40 CFR 98.86(a) and (b) to enhance the quality and accuracy of the data collected. In the 2022 Data Quality Improvements Proposal, the EPA proposed to add several data reporting elements based on annual average chemical composition data for facilities using either the direct measurement (using a continuous emission monitoring system (CEMS)) methodology or the mass balance methodology, in order to assist in improving verification of reported data. The proposed data elements included (for both facilities that report CEMS data and those that report using a mass balance method) the annual arithmetic average weight fraction of: the total calcium oxide (CaO) content, noncalcined CaO content, total magnesium oxide (MgO) content, and non-calcined MgO content of clinker at the facility (proposed 40 CFR 98.86(a)(4) through (a)(7) and (b)(19) through (b)(22)); and the total CaO content of cement kiln dust (CKD) not recycled to the kiln(s), non-calcined CaO content of CKD not recycled to the kiln(s), total MgO content of CKD not recycled to the kiln(s), and non-calcined MgO content of CKD not recycled to the kiln(s) at the facility (proposed 40 CFR 98.86(a)(8) through (11) and (b)(23) through (26)). The EPA also proposed to collect other data (from both facilities using CEMS and those that report using the mass balance method), including annual facility CKD not recycled to the kiln(s) in tons (proposed 40 CFR 98.86(a)(12) and (b)(27)) and raw kiln feed consumed annually at the facility in tons (dry basis) (proposed 40 CFR 98.86(a)(13) and (b)(28)), for both verification and to improve the methodologies of the Inventory. The EPA is finalizing the proposed requirements to report the annual arithmetic average weight fraction of the total CaO content, non-calcined CaO content, total MgO content, and noncalcined MgO content of clinker at the facility (proposed 40 CFR 98.86(a)(4) through (7) and (b)(19) through (22)), and the annual facility CKD not recycled to the kiln(s) (proposed 40 CFR 98.86(a)(12) and (b)(27), finalized as 40 CFR 98.86(a)(8) and (b)(27), respectively), for both facilities that use CEMS and those that report using the mass balance method. We are also finalizing, for facilities using the mass E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31824 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations balance method, the total CaO content of CKD not recycled to the kiln(s), noncalcined CaO content of CKD not recycled to the kiln(s), total MgO content of CKD not recycled to the kiln(s), and non-calcined MgO content of CKD not recycled to the kiln(s) at the facility (proposed 40 CFR 98.86(b)(23) through (26)), and the amount of raw kiln feed consumed annually (proposed 40 CFR 98.86(b)(28)). Finalizing these data elements will improve the EPA’s ability to verify reported emissions (e.g., the EPA will be able to create a rough estimate of process emissions at the facility and compare that to the reported total emissions, and check whether the ratio is within expected ranges). For facilities using CEMS, the finalized data elements will enable the EPA to estimate process emissions from facilities to provide a more accurate national-level cement emissions profile and the Inventory. Following consideration of public comments, we are not taking final action on certain proposed data elements for facilities that report using CEMS. Specifically, the EPA is not taking final action on the proposed requirements to report the annual arithmetic average of the total CaO content of CKD not recycled to the kiln(s), non-calcined CaO content of CKD not recycled to the kiln(s), total MgO content of CKD not recycled to the kiln(s), and non-calcined MgO content of CKD not recycled to the kiln(s) at the facility (proposed 40 CFR 98.86(a)(8) through (11)). We are also not taking final action on the reporting of the amount of raw kiln feed consumed annually (proposed 40 CFR 98.86(a)(13)). See section III.F.2. of this preamble for a summary of the related comments and the EPA’s response. The EPA is finalizing as proposed several clarifications and corrections to equations H–1, H–4, and H–5 included in the 2022 Data Quality Improvements Proposal. The final revisions to equation H–1 add brackets to clarify the summation of clinker and raw material emissions for each kiln, and update the definition of parameter ‘‘CO2 rm’’ to ‘‘CO2 rm,m’’ and clarify the raw material input is on a per-kiln basis. The final revisions to equation H–5 revise the inputs ‘‘rm,’’ ‘‘CO2 rm’’ (revised to ‘‘CO2 rm,m’’), and ‘‘TOCrm,’’ and add brackets to clarify that emissions are calculated as the sum of emissions from all raw materials or raw kiln feed used in the kiln. The final revisions to equation H– 4 correct the defined parameters for the quarterly non-calcined CaO content and the quarterly non-calcined MgO content of CKD not recycled to ‘‘CKDncCaO’’ and VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 ‘‘CKDncMgO,’’ respectively, to align with the parameters defined in the equation. 2. Summary of Comments and Responses on Subpart H This section summarizes the major comments and responses related to the proposed amendments to subpart H. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart H. Comment: One commenter objected to the EPA’s proposed addition of data reporting requirements for facilities reporting using the CEMS methodology. The commenter asserted that the new data requirements would add unnecessary burden without providing additional insight into cement industry GHG emissions or improving the quality or accuracy of the emissions data provided. The commenter stated that, under the new provisions, the EPA would essentially be requiring kilns that are currently using CEMS to report their emissions to verify their data by using the mass balance method, with associated reporting and recordkeeping. The commenter noted that CEMS are already required to meet extensive quality assurance and quality control requirements and have been determined as the most accurate means of measuring stack emissions. Further, the commenter reasoned that the EPA can accurately determine process emissions using already reported data, total kiln stack emissions data, and combustion emissions data, which they stated is included in the confidential monthly clinker production data and fuel use data provided using the Tier 4 methodology in subpart C. The commenter stated that it is well established by the scientific community that process emissions represent 60 percent of CO2 emissions from the kiln based on the standard chemistry of the cement manufacturing process, and that the currently reported data should be sufficient. The commenter also opposed the EPA’s proposed data reporting elements for facilities using the mass balance (non-CEMS) methodology, likewise insisting that the EPA can readily determine both process and combustion emissions from the existing reporting requirements. The commenter explained that (1) the reporting of total and noncalcined CaO and MgO is irrelevant to calculating CO2 process emissions as they are inherently non-carbonate; and PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 (2) in reference to the proposed CKD reporting requirement, calculating the CKD not recycled and the quantity of raw kiln feed at all kilns within a facility would add burden without providing any additional information about industry GHG emissions. The commenter also questioned the need for the additional data, stating that the EPA did not provide an explanation of how the additional data would be used separately from potentially verifying process emissions. The commenter also expressed concern that the addition of these data elements would justify regulatory overreach from other programs. Response: We disagree with the commenter’s statement that reporting additional data from facilities using CEMS will not enhance the EPA’s verification of the facility reported values. The EPA has encountered occasional instances of mistakes in reported CEMS data (e.g., from data entry mistakes), resulting in significant errors in reported emissions. Fuel use data are not provided to the EPA for cement plants that report emissions using CEMS. Currently, fuel use data are entered into the IVT to calculate CH4 and N2O emissions from combustion for kilns with CEMS, as the process and combustion emissions are both vented through the same stack. These IVT data are not directly reported to the EPA, so the EPA cannot use them to verify the accuracy of reported emissions. Furthermore, we are not persuaded by the commenter’s assertion that process emissions represent 60 percent of kiln emissions. Cement kilns can have very different process and combustion emissions depending on the input materials, the fuel or energy source used, etc., and an average process emissions factor would not be representative of all facilities in subpart H. Furthermore, the commenter does not provide additional information about how this statistic was calculated and whether it is representative of cement manufacturing plants in the United States. The commenter did not specify where this statistic can be found in the cited source (‘‘Getting the Numbers Right Database, Global Cement and Concrete Association’’ 9) and did not provide the underlying data to the EPA for review. Importantly, this database contains information on global cement production, and emissions profiles at facilities in the United States can differ widely from those in other countries due to differences in input 9 Available at https://gccassociation.org/ sustainability-innovation/gnr-gcca-in-numbers/. Accessed January 9, 2024. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations materials, fuels used, and emission control systems that may be in place. The EPA has reviewed data, such as those from the UNFCCC, which suggest that implied emissions rates may vary from 49–57 percent and change by country.10 Upon careful review and consideration, the EPA has decided not to adopt the proposed changes to require the chemical composition data for CKD and amount of raw kiln feed consumed annually for facilities reporting with CEMS (proposed 40 CFR 98.86(a)(8) through (11) and (a)(13)). We are not taking final action on these elements after consideration of the comments and in an effort to reduce potential burden. The EPA is finalizing the remaining proposed reporting requirements as these data elements will improve verification of reported emissions. For example, the EPA will be able to create a rough estimate of process emissions at the facility and compare that to the reported total emissions, and check whether the ratio is within expected ranges. We will also be able to build evidence-based verification checks on the clinker composition data that is entered by facilities that do not use CEMS (we currently have very little information on what chemical compositions are typical in cement kilns). The final reporting elements will also enable the EPA to estimate process emissions from CEMS facilities to provide a more accurate national-level emissions profile for the cement industry and the Inventory. Reporting average chemical composition data for the clinker is expected to be less burdensome for facilities, as this data is likely collected as a part of normal business operations, while collection of CKD data may be less common. Furthermore, we do not believe these additional data elements constitute regulatory overreach as they are similar to other data already collected under subpart H and will be important for verification and our understanding of process and combustion emissions. We also disagree that collecting additional data from facilities using the mass balance method will not enhance the EPA’s verification of the facility reported values. Currently clinker composition data are entered into the IVT and are not included in the annual report that is submitted to the EPA. Reporting of these and additional data elements will improve verification of reported emissions and the mass 10 United Nations Framework Convention on Climate Change. (2023). National inventory submissions 2023. https://unfccc.int/ghginventories-annex-i-parties/2023. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 balance calculations (e.g., by allowing us to create evidence-based verification checks for clinker composition data). The final reporting elements will also provide a more accurate national-level emissions profile for the cement industry and the Inventory. With respect to the burden associated with these added reporting elements for reporters using the mass balance reporting method, these data elements are the annual arithmetic averages of either monthly or quarterly data elements that these reporters already input into e-GGRT through the IVT. These data elements are currently entered into the IVT and used for equations H–2 through H–5; but they are not reported to the EPA. Thus, the burden, if any, is expected to be minimal. There are no changes, as compared to the proposal, to the final reporting requirements for facilities using the mass balance methodology after consideration of this comment. G. Subpart I—Electronics Manufacturing We are finalizing several amendments to subpart I of part 98 (Electronics Manufacturing) as proposed. In some cases, we are finalizing the proposed amendments with revisions. In other cases, we are not taking final action on the proposed amendments. Section III.G.1. of this preamble discusses the final revisions to subpart I. The EPA received several comments on the proposed subpart I revisions which are discussed in section III.G.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart I as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart I This section summarizes the final amendments to subpart I. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart I can be found in this section and section III.G.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Revisions To Improve the Quality of Data Collected for Subpart I In the 2022 Data Quality Improvements Proposal, the EPA proposed several revisions to subpart I to improve data quality, including PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 31825 revising the stack testing calculation method, updating the calculation methods used to estimate emission factors in the technology assessment report, updating existing default emission factors and destruction or removal efficiencies (DREs) based on new data, adding a calculation method for calculating byproducts produced in abatement systems, amending data reporting requirements, and providing clarification on reporting requirements. In the 2023 Supplemental Proposal, the EPA subsequently proposed corrections to specific revisions from the 2022 Data Quality Improvements Proposal, including DRE values in table I–16 and gamma factors in proposed new table I– 18 to subpart I of part 98. The EPA is finalizing several revisions to 40 CFR 98.93(i) to improve the calculation methodology for stack testing. These revisions include: • Adding new equations I–24C and I– 24D and a table of default weighting factors (new table I–18) to calculate the fraction of fluorinated input gases exhausted from tools with abatement systems, ai,f, for use in equations I–19A through I–19C and I–21, and the fraction of byproducts exhausted from tools with abatement systems, ak,i,f, for use in equations I–20 and I–22. • Revising equations I–24A and I– 24B, which calculate the weighted average DREs for individual F–GHGs across process types in each fab. • Revising 40 CFR 98.93(i)(3) to require that all stacks be tested if the stack test method is used. • Replacing equation I–19 with a set of equations (i.e., equations I–19A, I– 19B, and I–19C) that will more accurately account for emissions when pre-control emissions of an F–GHG come close to or exceed the consumption of that F–GHG during the stack testing period. • Clarifying the definitions of the variables dif and dkif, the average DREs for input gases and byproduct gases respectively, in equations I–19A, I–19B, I–19C, and I–19D, in equations I–20 through I–22, in equations I–24A and B, and in equation I–28 to subpart I. These revisions will remove the current requirements to apportion gas consumption to different process types, to manufacturing tools equipped versus not equipped with abatement systems, and to tested versus untested stacks. Equations I–24C and I–24D add the option to calculate the fraction of each input gas ‘‘i’’ and byproduct gas ‘‘k’’ exhausted from tools with abatement systems based on the number of tools that are equipped versus not equipped with abatement systems, along with weighting factors that account for the E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31826 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations different per-tool emission rates that apply to different process types. The weighting factors (gi,p for input gases and gk,i,p for byproduct gases, provided in table I–18) are based on data submitted by semiconductor manufacturers during the process of developing the 2019 Refinement (as corrected in the 2023 Supplemental Proposal). We are finalizing revisions to equations I–24A and I–24B, used to calculate the average DRE for each input gas ‘‘i’’ and byproduct gas ‘‘k,’’ based on tool counts and the same weighting factors that will be used in equations I– 24C and I–24D; this accounts for operations in which a facility uses one or more abatement systems with a certified DRE value that is different from the default to calculate and report controlled emissions. We are finalizing the requirement that all stack systems be tested by removing 40 CFR 98.93(i)(1); this removes not only the need to apportion gas usage to tested versus untested stack systems, but also the requirement to perform a preliminary calculation of the emissions from each stack system. We are finalizing new equations I–19A, I–19B, and I–19C, with a clarification, which will more accurately account for emissions when emissions of an F–GHG prior to entering any abatement system (i.e., pre-control emissions) would approach or exceed the consumption of that F–GHG during the stack testing period. We are clarifying that the 0.8 maximum for the 1–U value only applies to carboncontaining F–GHGs. As discussed in the proposal, the modification to the stack testing method was intended to accurately account for the source of emissions when the measured emissions exceed the consumption of the F–GHG during the stack testing period, which may occur in situations where the input gas is also generated in significant quantities as a by-product by the other input gases. However, it is not expected that NF3 or SF6 could be generated as a by-product by a fluorocarbon used as an input gas. Therefore, this modification is not appropriate and was not intended to apply to SF6 or NF3 emissions when calculating emissions using the stack test method. The revised equations improve upon the current equations because they account both for any control of the emissions and for some utilization of the input gas. Finally, we are finalizing revisions to the definitions of the variables dif and dkif in equations I–19A, I–19B, I–19C, and I– 19D, in equations I–20 through I–22, in equations I–24A and B, and in equation I–28 to clarify that these variables reflect the fraction of gas i (or byproduct gas k) VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 that is destroyed once gas i (or byproduct gas k) is fed into abatement systems. See section III.E.1.a. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. With some changes, the EPA is finalizing revisions to improve the quality of the data submitted in the technology assessment reports in 40 CFR 98.96(y) as proposed in the 2022 Data Quality Improvements Proposal. Specifically, the EPA proposed to require that reporters who submit a technology assessment report would use three methods (the ‘‘all-input gas method,’’ the ‘‘dominant gas method,’’ and the ‘‘reference emission factor method’’) to report the results of each emissions test to estimate utilization and byproduct formation emission rates. The EPA is finalizing a requirement to report the results using two of the three methods proposed, including the allinput gas method, with a clarification, and the reference emission factor method, and is allowing use of a third method of the reporter’s choice, as follows: • All-input gas method. For input gas emission rates, this method attributes all emissions of each F–GHG that is an input gas to the input gas emission factor (1–U) factor for that gas, if the input gas does not contain carbon or until that 1–U factor reaches 0.8 if the input gas does contain carbon, after which emissions of the F–GHG are attributed to the other input gases. For byproduct formation rates, this method attributes emissions of F–GHG byproducts that are not also input gases to all F–GHG input gases (kilogram (kg) of byproduct emitted/kg of all F–GHGs used). • Reference emission factor method. This method estimates emissions using the 1–U and the byproduct formation rates that are observed in single gas recipes and then adjusts both emission factors based on the ratio between the emissions calculated based on the factors and the emissions actually observed in the multi-gas process. • The EPA is finalizing an option for reporters to use, in addition to the utilization and byproduct formation rates calculated according to the required all-input gas method and the reference emission factor method, an alternative method of their choice to calculate and report the utilization or byproduct formation rates based on the collected data. These revisions will ensure that the emission factors submitted in the technology assessment reports are robust (for example, not unduly affected PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 by changing ratios of input gases) and are comparable to each other and to the emission factors already in the EPA’s database. The EPA proposed, and is finalizing with a clarification, modifications to the all-input gas method to avoid an input gas emission factor greater than 0.1 when multiple gases are used. The modified method uses 0.8 as the maximum 1–U value, and as such, attributes emissions of each F–GHG used as an input gas to that input gas until the mass emitted equals 80 percent of the mass fed into the process (i.e., until the 1–U factor equals 0.8). The all-input gas method assigns the remaining emissions of the F–GHG to the other input gases as a byproduct in proportion to the quantity of each input gas used in the process. We are finalizing this modified method with the clarification that the 0.8 maximum for the 1–U value only applies to carbon-containing F–GHGs. As discussed in the proposal, the modification to the all-input method was intended to avoid the situations where the historical methods would violate the conservation of mass or fail to reflect the fact that some fraction of the input gas reacts with the film it is being used to etch or clean, which may occur in situations where the input gas is also generated in significant quantities as a by-product by the other input gases. However, it is not expected that NF3 or SF6 could be generated as a by-product by a fluorocarbon used as an input gas. Therefore, this modification is not appropriate and was not intended to apply to SF6 or NF3 emissions when calculating emission factors. The EPA is requiring use of the all-input gas method to facilitate comparisons of new data to historical data; the all-input gas method was the most commonly used method in the submitted data sets included in technology assessment reports from 2013 and earlier. Following consideration of comments received and to reduce burden, the EPA is not taking final action on the proposed requirement to report emission factors using the dominant gas method. The dominant gas method calculates 1–U factors in the same way as the all-input gas method, but it calculates byproduct formation rates differently, attributing all emissions of F–GHG byproducts to the carbon-containing F–GHG input gas accounting for the largest share by mass of the input gases. Additional information on each of the three methods is available in section III.E.1.b. of the preamble to the 2022 Data Quality Improvements Proposal and in the memorandum ‘‘Technical Support for Modifications to the Fluorinated E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Greenhouse Gas Emission Estimation Method Option for Semiconductor Facilities under Subpart I,’’ available in the docket to this rulemaking, Docket ID. No. EPA–HQ–OAR–2019–0424. As noted in the proposed rule, the EPA intends to make available a calculation workbook for the technology assessment report that will calculate the two sets of emission factors based on each of the final methods using a single set of data entered by the reporter. The option to calculate the emission factors using an additional method provides flexibility for reporters while enabling comparison between the results of the additional method and the results of the two required methods. Where reporters choose to submit emission factors using the additional method, we will be able to evaluate the reliability and robustness of emission factors calculated using all three methods. Additional information on comments related to the calculation methods and the EPA’s response can be found in section III.G.2.a. of this preamble. The EPA is also finalizing two additional requirements for the submitted technology assessment reports including requiring reporters to specify (1) the method used to calculate the reported utilization and byproduct formation rates and assign and provide an identifying record number for each data set; and (2) for any DRE data submitted, whether the abatement system used for the measurement is specifically designed to abate the gas measured under the operating condition used for the measurement. For reporters who opt to additionally provide utilization and byproduct formation rates using an alternative method of their choice, reporters must provide this information and a description of the alternative method used. The EPA is finalizing revisions to update the default emission factors and DREs in subpart I based on new data submitted as part of the 2017 and 2020 technology assessment reports and the 2019 Refinement, as proposed in the 2022 Data Quality Improvements Proposal and corrected in the 2023 Supplemental Proposal. These revisions include: • Updates to the utilization rates and byproduct emission factors (BEFs) for F–GHGs used in semiconductor manufacturing in tables I–3, I–4, I–11 and I–12; • Removal of byproduct emission factors from tables I–3 and I–4 where there is a combination of both a low BEF and a low GWP resulting in very low reported emissions per metric ton of input gas used (removes the BEF for C4F6 and C5F8 for all input gases used VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 in wafer cleaning or plasma etching processes, and results in not adding BEFs for COF2 and C2F4 for any input gas/process combination from the new data submitted as part of the 2017 and 2020 technology assessment reports). • In cases where neither the input gas nor the films being processed in the tool contain carbon, setting the BEF for the carbon-containing byproducts to zero. These provisions apply at the process subtype level. For example, a BEF of zero will only be used for a combination of input gas and chamber cleaning process subtype (e.g., NF3 in remote plasma cleaning (RPC)) if no carboncontaining materials were removed using that combination of input gas and chamber cleaning process subtype during the year and no carboncontaining input gases were used on those tools. Otherwise, the default BEF will be used for that combination of input gas and chamber cleaning process subtype for all of that gas consumed for that subtype in the fab for the year. The EPA is making one modification to the proposed equation to clarify that the carbon-containing byproduct emission factors are zero when the combination of input gas and etching and wafer cleaning process type uses only noncarbon containing input gases (SF6, NF3, F2 or other non-carbon input gases) and etches or cleans only films that do not contain carbon. • Updates to the default emission factors for N2O used in all electronics manufacturing in table I–8, including distinct utilization rates for semiconductor manufacturing and LCD manufacturing and, for semiconductor manufacturing, utilization rates by wafer size; • Revisions to the calculation methodology for MEMS and PV manufacturing to allow use of 40 CFR 98.93(a)(1), the current methodology for semiconductor manufacturing, for manufacture of MEMS and PV using semiconductor tools and processes, which applies the default emission factors in tables I–3 and I–4 to these processes; • Revisions to 40 CFR 98.93(a)(6) to revise the utilization rate and byproduct emission factor values assigned to gas/ process combinations where no default utilization rate is available; these revisions account for the likely partial conversion of the input gas into CF4 and C2F6. The final rule requires, for a gas/ process combination where no default input gas emission factor is available in tables I–3, I–4, I–5, I–6, and I–7, reporters will use an input gas emission factor (1–U) equal to 0.8 (i.e., a default utilization rate or U equal to 0.2) with BEFs of 0.15 for CF4 and 0.05 for C2F6. PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 31827 • Revisions to the default DREs in table I–16 to subpart I to reflect new data and strengthening of abatement system certification requirements. The final revisions assign chemical-specific DREs to all commonly used F–GHGs for the semiconductor manufacturing subsector without distinguishing between process types. Additional information on the EPA’s derivation of the final emission factors and DREs is available in section III.E.1.c. of the preamble to the 2022 Data Quality Improvements Proposal and in the revised technical support document, ‘‘Revised Technical Support for Revisions to Subpart I: Electronics Manufacturing,’’ available in the docket for this rulemaking (Docket ID. No. EPA–HQ–OAR–2019–0424). The EPA is also finalizing revisions to the conditions under which the default DRE may be claimed, with some revisions from the proposal so that the new documentation requirements apply only to abatement systems purchased and installed on or after January 1, 2025. For all abatement systems for which a DRE is being claimed, including abatement systems purchased and installed during or after 2025 and older abatement systems, the EPA is maintaining the current certification and documentation requirements and is finalizing the proposed additional requirement that the certification must contain a manufacturer-verified DRE value. If the abatement system is certified to abate the F–GHG or N2O at a value equal to or higher than the default DRE, the facility may claim the default DRE. If the abatement system is certified to abate the F–GHG or N2O but at a value lower than the default DRE, the facility may not claim the default; however, the facility may claim the lower manufacturer-verified value. (Site-specific measurements by the electronics manufacturer are still required to claim a DRE higher than the default.) Based on annual reports submitted through RY2022, facilities have historically been able to provide manufacturer-verified DRE values for all abatement systems for which emission reductions have been claimed. Additional requirements apply to abatement systems purchased and installed on or after January 1, 2025. Specifically, the EPA is finalizing revisions to the definition of operational mode in 40 CFR 98.98 to specify that for abatement systems purchased and installed during or after January 1, 2025, operational mode means that the system is operated within the range of parameters as specified in the DRE certification documentation. The specified parameters must include the E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31828 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations highest total F–GHG or N2O flows and highest total gas flows (with N2 dilution accounted for) through the emissions control systems. Systems operated outside the range of parameters specified in the documentation supporting the DRE certification may rely on a measured site-specific DRE according to 40 CFR 98.94(f)(4) to be considered operational within the range of parameters used to develop a sitespecific DRE. The EPA is also finalizing revisions to 40 CFR 98.94(f)(3) to modify the conditions under which the default or lower DRE may be claimed for abatement systems purchased and installed on or after January 1, 2025. For systems purchased and installed on or after January 1, 2025, reporters are required to: (1) certify that the abatement device is able to achieve, under the worst-case flow conditions during which the facility is claiming that the system is in operational mode, a DRE equal to or greater than either the default DRE value, or if the DRE claimed is lower than the default DRE value, a manufacturer-verified DRE equal to or greater than the DRE claimed; and (2) provide supporting documentation. Specifically, for POU abatement devices purchased and installed on or after January 1, 2025, reporters must certify and document under 40 CFR 98.94(f)(3)(i) and (ii) that the abatement system has been tested by the abatement system manufacturer using a scientifically sound, industry-accepted measurement methodology that accounts for dilution through the abatement system, such as EPA 430–R– 10–003,11 and that the system has been verified to meet (or exceed) the destruction or removal efficiency used for that fluorinated GHG or N2O under worst-case flow conditions (the highest total F–GHG or N2O flows and highest total gas flows, with N2 dilution accounted for). Because manufacturers routinely conduct DRE testing and are familiar with the protocols of EPA 430– R–10–003, we anticipate this information will be readily available for abatement systems purchased in calendar year 2025 or later. The EPA is finalizing that the new DRE requirements will be implemented for reports prepared for RY2025 and submitted March 31, 2026, which provides over a year for reporters to acquire the necessary documentation. Reporters are not required to maintain 11 Protocol for Measuring Destruction or Removal Efficiency of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, March 2010 (‘‘EPA DRE Protocol’’), as incorporated at 40 CFR 98.7. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 documentation of the DRE on abatement systems for which a DRE is not being claimed. We are also clarifying that the list of abatement system manufacturer specifications within which the abatement system must be operated at 40 CFR 98.96(q)(2) is intended to be exemplary, adding ‘‘which may include, for example,’’ before the list. This clarifies that some of the listed specifications or parameters may not be specified by all abatement system manufacturers for all abatement systems, and leaves open the possibility that some abatement system manufacturers may include other specifications within which the abatement system must be operated. Additionally, following consideration of comments received, we are clarifying how reporters account for uptime of the abatement device if suitable backup emissions control equipment or interlocking with the process tool is implemented for each emissions control system. The EPA is revising the definition of the term ‘‘UTij’’ in equation I–15 and the definition of ‘‘UTf’’ in equation I–23 to clarify that if all the abatement systems for the relevant input gas and process type are interlocked with all the tools feeding them, the uptime may be set to one (1). We are also clarifying equations I–15 and I–23 to reference the provisions in 40 CFR 98.94(f)(4)(vi) when accounting for uptime when redundant abatement systems are used. See section III.G.2.a. of this preamble for additional information on related comments and the EPA’s response. The EPA is finalizing the addition of a calculation methodology that estimates the emissions of CF4 produced in hydrocarbon-fuel based combustion emissions control systems (‘‘HC fuel CECs’’) that are not certified not to generate CF4. Following consideration of public comments, the calculation will be required only for HC fuel CECs purchased and installed on or after January 1, 2025. To implement the new calculation methodology, we are adding a new equation I–9 and renumbering the previous equation I–9 as equation I–8B. Equation I–9 only applies to processes that use F2 as an input gas or to remote plasma cleaning processes that use NF3 as an input gas. Equation I–9 estimates the emissions of CF4 from generation in emissions control systems by calculating the mass of the fluorine entering uncertified HC fuel CECs (the product of the consumption of the input gas, the emission factor for fluorine, and ai, where ai is the ratio of the number of tools with uncertified abatement devices for the gas-process combination PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 to the total number of process tools for the gas-process combination) and multiplying that mass by a CF4 emission factor, ABCF4,F2, which has a value of 0.116. In related changes, the EPA is finalizing a BEF for F2 from NF3 used in remote plasma clean processes of 0.5. For other gas and process combinations where no data are available (listed as ‘‘NA’’ in tables I–3 and I–4), the EPA is finalizing a BEF of 0.8 be used for F2 in equation I–9 for all process types. The EPA is requiring that reporters estimate CF4 emissions from all HC fuel CECs that are purchased and installed on or after January 1, 2025 and that are not certified not to produce CF4, even if reporters are not claiming DREs for those systems. However, as noted above, the requirements apply only to HC fuel CECs used on processes that use F2 as an input gas or to remote plasma cleaning processes that use NF3 as an input gas. We are also finalizing a related definition of ‘‘hydrocarbon-fuelbased combustion emissions control system (HC fuel CECS),’’ which we have revised from the proposed ‘‘hydrocarbon-fuel-based emissions control system,’’ to align with the 2019 Refinement and to clarify that the term includes systems used on processes that have the potential to emit F2 or fluorinated GHGs, as recommended by commenters. As noted above, we have also revised the final rule from proposal to require these estimates from HC fuel CECS purchased and installed on or after January 1, 2025. We are also finalizing corresponding monitoring, reporting, and recordkeeping requirements (see 40 CFR 98.94(e), 40 CFR 98.96(o), and 40 CFR 98.97(b), respectively) for facilities that use HC fuel CECS purchased and installed during or after 2025 to control emissions from tools that use either NF3 as an input gas in RPC processes or F2 as an input gas in any process and assume in equation I–9 that one or more of those systems do not form CF4 from F2. Under these requirements facilities must certify and document that the model for each of the systems that the facility assumes does not form CF4 from F2 has been tested and verified to produce less than 0.1 percent CF4 from F2, and that each of these systems is installed, operated, and maintained in accordance with the directions of the HC fuel CECS manufacturer. The facility may perform the testing itself, or it may supply documentation from the HC fuel CECS manufacturer that supports the certification. Because the requirement to quantify emissions of CF4 from F2 is being applied only to HC fuel CECS purchased and installed on or after E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 January 1, 2025, we anticipate that most HC fuel CECS will be tested by the HC fuel CECS manufacturer. If the facility performs the testing, it is required to measure the rate of conversion from F2 to CF4 using a scientifically sound, industry-accepted method that accounts for dilution through the abatement device, such as the EPA DRE Protocol, adjusted to calculate the rate of conversion from F2 to CF4 rather than the DRE. The EPA is also finalizing related amendments to 40 CFR 98.94(j)(1)(i) to require that the uptime (i.e., the fraction of time that abatement system is operational and maintained according to the site maintenance plan for abatement systems) during the stack testing period average at least 90 percent for uncertified HC fuel CECS. Following consideration of comments received, we are clarifying in the final rule that these provisions are limited to only those HC fuel CECS that were purchased and installed on or after January 1, 2025, that are used to control emissions from tools that use either NF3 in remote plasma cleaning processes or F2 as an input gas in any process type or subtype, and that are not certified not to form CF4. See section III.G.2.a. of this preamble for additional information on related comments on HC fuel CECS and the EPA’s response. Finally, the EPA is not taking final action on proposed revisions to the calibration requirements for abatement systems. In the 2022 Data Quality Improvements Proposal, the EPA proposed that a vacuum pump’s purge flow indicators are calibrated every time a vacuum pump is serviced or exchanged, with the expectation that this requirement would require calibrations every one to six months, depending on the process. Following review of input provided by commenters, we are not taking final action on the proposed revisions. Removal of the proposed requirements is anticipated to reduce the potential burden on reporters without any large effects on data quality. Section III.G.2.a. of this preamble provides additional information on the comments received related to vacuum pump purge flow calibration and the EPA’s response. b. Revisions To Streamline and Improve Implementation for Subpart I In the 2022 Data Quality Improvements Proposal, the EPA proposed several revisions intended to streamline the calculation, monitoring, or reporting in specific provisions in subpart I to provide flexibility or increase the efficiency of data collection. The EPA is finalizing these VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 changes as proposed. First, the final rule revises the applicability of subpart I as follows: • Adds a second option in 40 CFR 98.91(a)(1) and (2) for estimating GHG emissions for semiconductor, MEMS, and LCD manufacturers, for comparison to the 25,000 mtCO2e per year emissions threshold in 40 CFR 98.2(a)(2), that is based on gas consumption in lieu of production capacity. The revisions include new equations I–1B and I–2B to multiply gas consumption by a simple set of emission factors, the gas GWPs, and a factor to account for heat transfer fluid to estimate emissions. The emission factors are included in new table I–2 to subpart I of part 98 and are the same as the emission factors for gas and process combinations for which there is no default in tables I–3, I–4, or I–5 to subpart I. Facilities that choose to use this option for their calculation method will be required to track annual gas consumption by GHG but are not required to apportion consumption by process type for the purposes of assessing rule applicability. • Revises the current applicability calculation for PV manufacturers to revise equation I–3 and refer to new table I–2, and delete the phrase ‘‘that have listed GWP values in table A–1,’’ to increase the accuracy of the estimated emissions for determining applicability; and • Updates the emission factors in table I–1 to subpart I of part 98 used in the current applicability calculations for MEMS and LCD manufacturers based on new Tier 1 emission factors in the 2019 Refinement. Additional information on the EPA’s revisions to applicability and the final emission factors is available in section III.E.2.a. of the preamble to the 2022 Data Quality Improvements Proposal. The EPA additionally proposed, and is finalizing, to revise the frequency and applicability of the technology assessment report requirements in 40 CFR 98.96(y), which applies to semiconductor manufacturing facilities with GHG emissions from subpart I processes greater than 40,000 mtCO2e per year. First, we are finalizing amendments to 40 CFR 98.96(y) to decrease the frequency of submission of the reports from every three years to every five years. As we noted in the preamble to the 2022 Data Quality Improvements Proposal, revising the frequency of submission to every five years will increase the likelihood that reports will include updates in technology rather than conclusions that technology has not changed. At the time of proposal, this would have moved the due date for the next technology PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 31829 assessment, from March 31, 2023, to March 31, 2025. Because the EPA is not implementing the revisions in this final rule until January 1, 2025, we have revised the provision in the final rule to clarify that the first technology assessment report due after January 1, 2025 is due on March 31, 2028. Section III.G.2.b. of this preamble provides additional information on the comments received related to the frequency of submittal of the technology assessment report and the EPA’s response. We are also finalizing revisions to restrict the reporting requirement in 40 CFR 98.96(y) to facilities that emitted greater than 40,000 mtCO2e and produced wafer sizes greater than 150 mm (i.e., 200 mm or larger) during the period covered by the technology assessment report, as well as explicitly state that semiconductor manufacturing facilities that manufacture only 150 mm or smaller wafers are not required to prepare and submit a technology assessment report. The final provisions also clarify that a technology assessment report need not be submitted by a facility that has ceased (and has not resumed) semiconductor manufacturing before the last reporting year covered by the technology assessment report (i.e., no manufacturing at the facility for the entirety of the year immediately before the year during which the technology assessment report is due). 2. Summary of Comments and Responses on Subpart I This section summarizes the major comments and responses related to the proposed amendments to subpart I. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart I. a. Comments on Revisions To Improve the Quality of Data Collected for Subpart I Comment: The EPA received several comments related to the proposed revisions to the stack testing calculation methodology in subpart I. Largely, commenters objected to the EPA’s proposal that ‘‘all stacks’’ be tested. The commenters questioned the use of the terminology ‘‘all stacks’’ within the proposed preamble and disagreed with the EPA’s assumption that the number of stacks at each fab is expected to be small (e.g., one to two). The commenters provided input from an industry survey of 33 fabs, suggesting that over 250 E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31830 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations stacks would require testing, as well as an additional 170 process stacks that do not contain F–GHGs (e.g., general fab exhausts). The commenters urged that adding stacks that do not have the potential to emit F–GHGs to the stack testing scope would add an additional $60,000 to $200,000 per testing event and as much as $400,000 for large sites. The commenters requested the EPA clarify that the testing is required for all operating stacks or stack systems that have the potential to emit F–GHGs, and that the rule retain the current terminology of ‘‘stack system.’’ Response: Even though the EPA referred to ‘‘all stacks’’ in the proposal preamble, we agree that the testing is required only for all operating stack systems. The proposed and final regulatory text continue to use the term ‘‘stack system,’’ which is defined as ‘‘one or more stacks that are connected by a common header or manifold, through which a fluorinated GHGcontaining gas stream originating from one or more fab processes is, or has the potential to be, released to the atmosphere. For purposes of this subpart, stack systems do not include emergency vents or bypass stacks through which emissions are not usually vented under typical operating conditions.’’ We are finalizing the proposed requirement that all stack systems must be tested in accordance with 40 CFR 98.93(i)(3)(ii). Comment: The EPA received comments objecting to proposed revisions to the technology assessment report to require use of three proposed calculation methods (i.e., the dominant input gas method, all-input gas method, and reference emission factor method) to develop utilization and byproduct emission factors. The commenters expressed that each of EPA’s proposed methods fails to meet the agency’s goals for consistent implementation of emission factors across facilities and to allow for comparability across the industry and in industry emission rates. Specifically, the commenters asserted that the dominant input gas method and all-input gas method violate the physical reality of conservation of mass for plasma etch/wafer cleaning processes when using multiple gases and may lead to byproduct emission factors greater than 1. The commenters continued that the dominant input gas method does not clearly define what gas would be dominant in situations where gases of equal or near-equal mass are used. For both of the all-input gas method and the dominant input gas method, the commenters criticized the use of a ‘‘cap’’ value of 0.8 as inconsistent with the agency’s goal to VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 calculate emission factors consistently with those already in the EPA’s data set. For the all-input gas method, commenters added that the cap of 0.8 for individual testing does not align with the maximum seen within historical test data submitted by industry, but is instead aligned with the maximum average emission factor across all gases. Commenters stated that the modification to both methods may amplify or obfuscate technology changes by setting an artificial maximum emissions value. The commenters also stated that it is unclear how the reference emission factor method would be implemented. Specifically, commenters questioned whether 1–U or the byproduct emission factors would be held constant, maintaining that the method increases the difficulty in comparing individual tests depending on what is held constant, and adding that if new gases or byproducts are used or measured, the methodology will not have a reference emission basis to apply. Commenters expressed that the additional burden and complexity of calculating technology emission factors three different ways could be a disincentive to facility testing and would not improve overall emissions accuracy. The commenters requested that in lieu of the three calculation methods, the EPA consider use of the ‘‘multi-gas method,’’ which attributes all noncarbon-containing GHGs, such as SF6 and NF3, to the input of these noncarbon-containing GHGs and attributes all carbon-containing F–GHG emissions across all carbon-based input F–GHGs. The commenters believe that the multigas method would appropriately assign emissions (especially for recipes running more than two gases at once), would eliminate concerns regarding emission factors that do not meet conservation of mass principles, and is not reliant on past or assumed data to calculate emission factors or byproduct emission factors. Commenters explained that high variability in single-gas emission factors is due to a variety of factors, including the amount or concentration of input gases, as well as plasma and manufacturing tool variables, and suggested that use of the multi-gas method would generate emission factors consistent and within the range of the existing emission factor data, while also being able to accommodate new gases and changes in technology. Response: The EPA disagrees with the commenter’s assessment of the three proposed emission factor methods. We also disagree that the proposed requirements are overly burdensome. PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 However, following consideration of the comments raised, we are revising the final rule to require reporters to estimate emission factors using two of the three proposed methods (the all-input gas method and the reference emission factor method) and to allow reporters to submit results using an additional method of their choice. As noted in the preamble to the proposed rule, we plan to provide a spreadsheet that will automatically perform the calculations for the two required methods using a single data set entered by the reporters, minimizing burden. As explained in both section III.E.1.b. to the preamble to the 2022 Data Quality Improvements proposal and the subpart I technical support document,12 the all-input gas method is quite consistent with the historically used methods, differing from the historically used methods only under circumstances where the historically used methods are likely to yield unrealistic results (e.g., where CF4 is used as an input gas and accounts for a small fraction of the mass of all input gases, yielding CF4 input gas emission factors over 0.8). Of the three methods proposed, the reference emission factor method is somewhat less consistent with the historically used methods, but is expected to be more robust in that its results are less affected by changing ratios of input gases. As discussed further below, both of these methods are more consistent with the historical methods and less affected by changing input gas ratios than the method favored by the commenter, the multi-gas method. After consideration of comments, the EPA is not taking final action on the proposed requirement to report emission factors calculated using the dominant gas method for several reasons. First, the dominant gas method estimates the input gas emission rate in the same way as the all-input gas method, making it redundant with the all-input gas method for calculation of input gas emission rates. Second, the dominant gas method estimates the byproduct emission rate by assigning all emissions of F–GHG byproducts to the carbon-containing F–GHG input gas accounting for the largest share by mass of the input gases, which is anticipated, as noted by commenters, to be less accurate in cases where input gases of equal or near-equal mass are used. Third, in the historical data sets submitted to the EPA, the all-input gas method was the most commonly used 12 See document ‘‘Technical Support for Proposed Revisions to Subpart I (2022),’’ available in the docket for this rulemaking, Docket ID. No. EPA–HQ–OAR–2019–0424. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations method; therefore, retaining this approach rather than the dominant gas method will allow the EPA to more reliably compare the new data submitted to the historical data set. Finally, not requiring use of the dominant gas method will reduce burden on facilities that are required to submit technology assessment reports. As noted in the preamble to the 2022 Data Quality Improvements proposal, receiving results based on multiple methods will enable the EPA: (1) to directly compare the new emission factor data to the emission factor data that are already in the EPA’s database and that were calculated using the historical method; and (2) to compare the results across the available emission factor calculation methods and to identify any systematic differences in the results of the different methods for each gas and process type. By identifying and quantifying systematic differences in the results of the different methods, we will be better able to distinguish these differences from differences attributable to technology changes. Knowledge of these systematic differences will also be useful in the event that we ultimately require facilities to submit emission factors using one method only, particularly if that method is not closely related to one of the methods used historically. We will also be able to evaluate how much the results of each method vary for each gas and process type; high variability may indicate that the results of a method are being affected by varying input gas proportions rather than differences in gas behavior. On the other hand, extremely low variability may also indicate that a method is affected by input gas proportions. For example, if the all-input-gas method yields a large number of input gas emission factors equal to 0.8, the maximum allowed value for input gas emission factors under this method, this implies that some of the emissions being attributed to the input gas are actually being generated as byproducts from other input gases that are collectively more voluminous, conditions under which the reference emission factor method may yield the most reliable results. Ultimately, these analyses will enable us to more accurately characterize emissions from semiconductor manufacturing by selecting the most robust emission factor data for updating the default emission factors in tables I– 3 and I–4. Note that the EPA would update the default emission factors using the rulemaking process, providing an opportunity for industry to comment VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 on the data and methodology used to develop any proposed factors. Regarding the comment that the proposed rule did not clarify how the reference emission factor would be implemented, including whether the 1– U or by-product emission factors would be adjusted, the proposed rule made it clear that both the 1–U and byproduct emission factors would be adjusted where the emitted gas was also an input gas. The preamble to the proposed rule stated, ‘‘the reference emission factor method calculates emissions using the 1–U and the BEFs [by-product emission factors] that are observed in single gas recipes and then adjusts both factors based on the ratio between the emissions calculated based on the factors and the emissions actually observed in the multi-gas process. This approach uses all the information available on utilization and by-product generation rates from single-gas recipes while avoiding assumptions about which of these are changing in the multi-gas recipe’’ (87 FR 36947). The proposed equations I–31A (for 1–U factors, finalized as equation I–30A) and I–31B (for by-product factors, finalized as equation I–30B) showed this in mathematical terms and also showed how the method would apply where more than two input gases were used. The proposed rule also clearly indicated that where a by-product gas was not also an input gas, proposed equation I–30B (finalized as equation I–29B) was to be used. Equation I–29B is the equation used in the all-input-gas method as well as the reference emission factor method for by-products that are not also input gases. Equation I–29B would apply to newly observed as well as previously observed by-product gases that were not also input gases. This leaves only the situation where an input gas is used in a process type for the first time along with other input gases. While we expect that this situation will be rare, we agree that it should be addressed. We are clarifying in the final rule that where an input gas is used in a process type with other input gases and there is no 1–U factor for that input gas in table I–19 or I–20, as applicable, the Reference Emission Factor Method will not be used to estimate the emission factors for that process. We are not specifying the multi-gas method as the sole method for calculating emission factors submitted in the technology assessment report. As noted in the proposed rule, one of the EPA’s goals in collecting emission factor data through the technology assessment report is to better understand how emission factors may be changing as a PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 31831 result of technological changes in the semiconductor industry, and whether the changes to the emission factors may justify further data collection to comprehensively update the default emission factors in tables I–3 and I–4. To meet this goal, the emission factors submitted in the technology assessment reports should be calculated using methods that are similar to the methods used to calculate the emission factors already in the EPA’s database; otherwise, differences attributable to differences in calculation methods may amplify or obscure differences attributable to technology changes. The multi-gas method assigns emissions of all carbon-containing F–GHGs to all carbon-containing F–GHG input gases, regardless of species, yielding input gas emission factors that are equal to byproduct gas formation factors for each emitted F–GHG. These input gas and byproduct gas emission factors are significantly different from the input gas and byproduct gas emission factors yielded by the historically used methods, making it difficult to discern the impact of technology changes as opposed to calculation method changes on the emission factors. In addition, our analysis indicated that the multi-gas method results are highly sensitive to the ratios of the masses of input gases fed into the process, which appears likely to affect the robustness and reliability of emission factors calculated using that method.13 For these reasons, we have concluded that it would not be appropriate to require submission of emission factors using only the multigas method. However, we are providing an option in the final rule for reporters to use, in addition to the required all-input gas method and the reference emission factor method, an alternative method of their choice to calculate and report updated utilization or byproduct formation rates based on the collected data. Reporters will therefore have the opportunity to provide emission factor data that are calculated using the multigas method or other methodologies, provided the reporter provides a complete, mathematical description of the alternative calculation method and labels the data calculated using that method consistent with the requirements for the all-input gas method and the reference emission factor method. Submitting emission factors calculated using the multi-gas 13 Id. The EPA has included in the docket a memo and spreadsheet showing the results of the different emission factor calculation methods using the same data (see Docket ID. No. EPA–HQ–OAR–2019– 0424–0142, memorandum and attachment 3 Excel spreadsheet). E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31832 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations method along with the other two methods would allow us to compare the results of the multi-gas method to the results of the other two (one of which is very similar to the primary historically used method) and to identify any systematic differences. As noted above, by identifying and quantifying systematic differences in the results of the different methods, we will be better able to distinguish these differences from differences attributable to technology changes. We may also be able to relate the results of the historical methods to the results of methods that differ from those used historically. Receiving emission factors calculated using three methods would also allow us to better assess the robustness and reliability of the emission factors calculated using all three methods, e.g., by seeing which methods yield highly variable emission factors within each input gas-process type combination. Because the final rule does not require reporters to submit emission factors calculated using an alternative methodology, the requirement to provide a complete, mathematical description of the alternative calculation method used is not anticipated to add significant burden. Comment: Commenters supported the proposal to remove BEFs for C4F6 and C5F8 and the decision to not add COF2 and C2F4, as byproduct emissions of them account for <<0.001% of overall GHG emissions from semiconductor manufacturing operations. One commenter also requested the EPA clarify that carbon-containing byproduct emission factors are zero when calculating emissions from non-carbon containing input gases (SF6, NF3, F2, or other non-carbon input gases) and when the film being etched or cleaned does not contain carbon, as this would align the EPA final rule with the 2019 Refinement. Response: The EPA is finalizing the rule as proposed to remove the BEFs for C4F6 and C5F8. The EPA is also not adding BEFs for COF2 or C2F4. For noncarbon containing input gases used in cleaning processes, we proposed to set carbon-containing byproduct emission factors to zero when the combination of input gas and chamber cleaning process sub-type is never used to clean chamber walls on manufacturing tools that process carbon-containing films during the year (e.g., when NF3 is used in remote plasma cleaning processes to only clean chambers that never process carbon-containing films during the year). We agree with the commenter that non-carbon-containing input gases used in etching processes are similarly not expected to give rise to carbon- VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 containing byproducts if neither the input gases nor the films being etched contain carbon. We are therefore finalizing an expanded version of the proposed provision, setting carboncontaining byproduct emission factors to zero for etching and wafer cleaning processes as well as chamber-cleaning processes when these conditions are met. The revisions align the rule requirements with the 2019 Refinement. Comment: Commenters expressed several concerns regarding the EPA’s proposed revisions to the conditions under which the default DRE may be claimed. One commenter requested the EPA remove the requirement to provide supporting documentation for all abatement units using certified default or lower than default DREs. The commenter also requested the EPA clarify that reporters are not required to maintain supporting documentation on abatement units for which a DRE is not being claimed. Commenters also contended that the existing language in subpart I is sufficient to ensure proper point-of-use (POU) device performance while being consistent with the 2019 Refinement, and the requirement to provide supporting documentation of manufacturer certified POU DREs, including testing method, is burdensome and may be unachievable, especially for older abatement units. One commenter expressed concern that the proposed increase in certification and documentation requirements beyond existing POU operational requirements will dissuade semiconductor companies from accounting for DREs from installed POU, resulting in an over-estimate of emissions from the semiconductor industry. The commenter also stated that adding operational elements of fuel and oxidizer settings, fuel gas flows and pressures, fuel calorific values, and water quality, flow, and pressures to the POU DRE requirements are outside the manufacturer-specified requirements for emissions control and are not necessary to ensure accurate POU DREs. Commenters stated that abatement equipment installed across the industry does not have manufacturer specifications for all listed parameters, or the capability to track all listed parameters. Commenters concluded that these and other POU default DRE certification and documentation requirements go above and beyond the 2019 Refinement and will make it more difficult for U.S. reporters to take credit for installed and future emissions control devices, resulting in a less accurate, overestimated GHG emissions inventory. One commenter supported PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 applying the requirements only to equipment purchased after the reporting rule becomes effective. The commenter stated that verification testing would be especially burdensome; the commenter estimated testing to take approximately 20 weeks per chemistry and stated it could take up to 2+ years for individual vendors to have required documentation. The commenter also expressed concern that the proposed requirements could have cascading impacts to facility manufacturing and operating permits based on state implementation of the Tailoring Rule, which typically rely on GHGRP protocols. Commenters supported aligning the emission control device operational requirements for default POU DREs with the following 2019 Refinement language: ‘‘. . . obtain a certification by the emissions control system manufacturers that their emissions control systems are capable of removing a particular gas to at least the default DRE in the worst-case flow conditions, as defined by each reporting site.’’ The commenter also requested the EPA include language supporting full uptime for emission control devices interlocked with manufacturing tools or with abatement redundancy. The commenter supported 2019 Refinement language that: ‘‘Inventory compilers should also note that UT [uptime] may be set to one (1) if suitable backup emissions control equipment or interlocking with the process tool is implemented for each emissions control system. Thus, using interlocked process tools or backup emissions control systems reduces uncertainty by eliminating the need to estimate UT for the reporting facility.’’ The commenter contended that such language will drive further use of manufacturing tool interlocks or emission control system redundancy while having the added benefit of simplifying uptime tracking of individual POU. Response: The EPA is clarifying in this response that reporters are not required to maintain documentation of the DRE on abatement units for which a DRE is not being claimed. However, no regulatory changes are needed to reflect this clarification. For abatement units for which a DRE is being claimed, reporters are still required to provide certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N2O abatement, as applicable, and support the certification by providing abatement system supplier documentation stating that the system was designed for fluorinated GHG or N2O abatement. The facility must certify E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations that the DRE provided by the abatement system manufacturer is greater than or equal to the DRE claimed (either the default, if the certified DRE is greater than or equal to the default, or the manufacturer-verified DRE itself, if the certified DRE is lower than the default DRE). To use the default or lower manufacturer-verified destruction or removal efficiency values, operation of the abatement system must be within the manufacturer’s specifications. It was not the EPA’s intent to require that certified abatement systems that operate within the manufacturer’s specifications must meet all the operational parameters listed, and we are revising the final rule at 40 CFR 98.96(q)(2) to add ‘‘which may include, for example,’’ to clarify that, in order to use the default or lower manufacturer-verified destruction or removal efficiency values, operation of the abatement system must be within those manufacturer’s specifications that apply for the certification. In the final rule, the EPA is maintaining the current certification and documentation requirements for older POU abatement devices, although the certification must contain a manufacturer-verified DRE value that is equal to or higher than the default in order to claim the default DRE; facilities are allowed to claim a lower manufacturer-verified value if the provided certified DRE is lower than the default. The EPA concurs that some older POU abatement systems may not have full documentation from the manufacturer of the test methods used and whether testing was conducted under worst-case flow conditions; however, we believe this documentation should be available for most newer abatement systems. As a result, reporters with the older POU abatement devices will not have any additional documentation requirements beyond those currently in place, except to provide the certified DRE. Following a review of annual reports submitted under subpart I, we determined that facilities have historically provided manufacturer-verified DRE values for all abatement systems for which emission reductions have been claimed. Therefore, we have determined that these final requirements are reasonable. The EPA is finalizing the new documentation requirements for POU abatement devices purchased on or after January 1, 2025 under 40 CFR 98.94(f)(3)(i) and (ii), these additional requirements include that the manufacturer-verified DREs reflect that the abatement system has been tested by the manufacturer using a scientifically VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 sound, industry-accepted measurement methodology that accounts for dilution through the abatement system, such as the EPA DRE Protocol (EPA 430–R–10– 003), and verified to meet (or exceed) the default destruction or removal efficiency for the fluorinated GHG or N2O under worst-case flow conditions. Since manufacturers routinely conduct DRE testing and are familiar with the protocols of EPA 430–R–10–003, this information would be readily available for abatement systems purchased in calendar year 2025 or later. Further, these final rule requirements will be implemented for reports prepared for RY2025 and submitted March 31, 2026, providing adequate time for reporters to acquire documentation. The EPA agrees with the recommendation to align the rule with the 2019 Refinement with respect to the uptime factor for interlocked tools and abatement systems and is making this change in the final rule. The use of interlocked tools is already accounted for in the current rule in the definition of terms ‘‘UTijp’’ and ‘‘UTpf’’ in equations I–15 and I–23 (the total time in minutes per year in which the abatement system has at least one associated tool in operation), which state that ‘‘[i]f you have tools that are idle with no gas flow through the tool for part of the year, you may calculate total tool time using the actual time that gas is flowing through the tool.’’ However, to clarify and simplify the calculation of uptime where interlocked tools are used, the EPA is revising the definition of the term ‘‘UTij’’ in equation I–15 to say that if all the abatement systems for the relevant input gas and process type are interlocked with all the tools feeding them, the uptime may be set to one (1). The revised text specifies that ‘‘all’’ tools and abatement systems for the relevant input gas and process sub-type or type are interlocked because the numerator and denominator of the uptime calculation in equations I–15 and I–23 are separately summed across abatement systems for input gas ‘‘i’’ and process sub-type or type ‘‘j.’’ Similar changes are made for the same reasons in the definition of ‘‘UTf’’ in equation I– 23. With the use of an interlock between the process tool and abatement device, the process tool should never be operating when the abatement device is not operating. The current rule also accounts for the use of redundant abatement systems. Section 98.94(f)(4)(vi) currently states, ‘‘If your fab uses redundant abatement systems, you may account for the total abatement system uptime (that is, the time that at least one abatement system is in operational mode) calculated for a PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 31833 specific exhaust stream during the reporting year.’’ This provision achieves nearly the same objective as suggested by the commenters. To clarify this point, the EPA is revising the definition of the terms ‘‘Tdijp’’ in equation I–15 and ‘‘Tdpf’’ in equation I–23 to reference the provision in 40 CFR 98.94(f)(4)(vi) when accounting for uptime when redundant abatement systems are used. Comment: Commenters objected to the EPA’s proposed requirements to include a calculation methodology to estimate emissions of CF4 produced in hydrocarbon-fuel based combustion emissions control systems (HC fuel CECS) that are not certified not to generate CF4. The commenters claimed that the CF4 byproduct emissions from HC fuel CEC abatement of F2 gas (from etch or remote plasma chamber cleaning processes) are based on limited and unverified data. Specifically, the commenters expressed concern that the values documented within the 2019 Refinement and referenced within the proposal are based on a single, confidential data set from one abatement supplier. One commenter stated that developing regulatory language around this single, unverified data set does not accurately represent the CF4 byproduct emissions from the uses or generation of F2 and may deliver an advantage to the single emissions control system supplier that provided the data. The commenters also listed the following concerns with the information provided within the 2019 Refinement and the proposed rule supporting documentation upon which the CF4 byproduct (ABCF4,F2 and BF2,NF3) is based: • The F2 emission values presented in ‘‘Influence of CH4-F2 mixing on CF4 byproduct formation in the combustive abatement of F2’’ by Gray & Banu (2018) are based on testing conducted in a lab under conditions that are not found in actual semiconductor abatement installations. Test methods do not appear to adhere to those specified in industry standard test methods or the EPA DRE Protocol. F2 results are measured from a device, the MST Satellite XT, designed to provide ‘‘nominal’’ F2 concentrations meant for health and safety risk management and not for environmental emissions measurement. • ‘‘FTIR spectrometers measure scrubber abatement efficiencies’’ by Li, et al. (2002) and ‘‘Thermochemical and Chemical Kinetic Data for Fluorinated Hydrocarbons’’ by Burgess, et al. (1996) provide anecdotal and hypothetical emission pathways for the combustion of fluorinated gases, but do not confirm E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31834 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations reliable and peer reviewed CF4 emission results from current semiconductor manufacturing use or generation of F2. • EPA references a single, confidential data set from Edwards, Ltd. (2018) upon which numerical ABCF4,F2 and BF2,NF3 values are based. This single data set of 15 measurements refers to an RPC NF3 to F2 emission value based on mass balance. The commenter opposed using the data provided by Edwards confidentially without the ability to review the underlying data and experimental procedure of the 15 measurements upon which the RPC NF3 to F2 emission factor was based. Mass balance has shown to be a highly conservative method in estimating emission factors and this confidential data set lacks visibility into repeatability, experimental design, and semiconductor process applicability. The commenters further contended that the requirement to calculate CF4 emissions from HC fuel CECS abatement of F2, based on equation I–9 if the HC fuel CECS is not certified to not convert F2 at less than 0.1%, adds complexity to apportioning RPC NF3 and F2 to both <0.1% certified and uncertified HC fuel CECS and will require time and cost investments which are not justified by data. One commenter added that this could disincentivize the use of low emission NF3 cleans or potentially slow implementation of F2 processes with zero-GWP potential due to the requirement to report CF4 BEF generation with tools with POU abatement. Another commenter added that this requirement appears to apply to all relevant HC fuel CECS regardless of whether a default or measured DRE is claimed for the abatement device. The commenter stated that if HC fuel CECS abatement suppliers and device manufacturers are not able to provide the required certification to exempt systems from this added emission, for every kilogram of RPC NF3 used, CO2e emissions out of the HC fuel CECS will increase more than 600% for 200 mm and more than 400% for 300 mm processes. Commenters added that this jump in CF4 emissions will result in a time series inconsistency for semiconductor industry greenhouse gas reporting. One commenter also stated that, if EPA maintains this requirement, it is unclear if equation I–9 applies in addition to or in place of existing CF4 byproduct emission factors. The commenter requested that CF4 emissions from the HC fuel CECS abatement of F2, as calculated by equation I–9, are applied instead of, not in addition to, default CF4 BEFs for RPC NF3. Commenters requested the removal VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 of equation I–9 and associated ABCF4,F2 and BF2,NF3 data elements; one commenter added that an alternative would be to make changes to HC fuel CECS requirements to remove confusion and double counting of emissions. Response: The EPA disagrees with the commenter after a thorough review of the issue, as documented in detail in a memorandum in the docket for the final rulemaking.14 The analysis conducted for the EPA demonstrated that: (1) the formation of CF4 by reaction of CH4 and F2 in POU combustion systems is thermodynamically favored and that there is no question that CF4 emissions can be observed if mixing of CH4 and F2 is allowed to occur; (2) that a revised BF2,NF3 default emission factor of 0.5 is well supported by scientific peerreviewed evidence to describe the formation of F2 from NF3-based RPC processes; (3) that the proposed default value for ABCF4,F2 of 0.116, describing the rate of formation of CF4 from F2, is well supported by experimental evidence under conditions that are representative of the designs and use of commercially available POU emissions control systems in production conditions; (4) that there is strong prima facie evidence of the formation of CF4 from within POU emissions control systems during the production of semiconductor devices; and (5) that not reporting such CF4 emissions could lead to a significant underestimation of GHG emissions from semiconductor manufacturing facilities. Based on the evidence documented in the memorandum, the EPA is finalizing as proposed the requirement that the electronic manufacturers estimate and report CF4 byproduct emissions from hydrocarbon-fuel-based POU emissions control systems that abate F2 processes or NF3-based RPC processes. The EPA is also requiring that reporters estimate CF4 emissions from all POU abatement devices that are not certified not to produce CF4, even if they are not claiming a DRE from those devices, because the CF4 emissions from HC fuel combustion in the abatement of F2 or F–GHG is a separate issue from whether or not a DRE is claimed for the same devices. The EPA disagrees that the rule is adding unnecessary complexity to apportion RPC NF3 and F2 between POU abatement systems that are certified not to convert F2 to CF4 and those that are not certified. Reporters 14 Memorandum from Sebastien Raoux to U.S. EPA. ‘‘CF4 byproduct formation from the combustion of CH4 and F2 in Point of Use emissions control systems in the electronics industry.’’ Prepared for the U.S. EPA. May 2023, available in the docket for this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424. PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 will use tool counts in this case rather than the usual gas apportioning model. This should be straightforward because it requires the reporters to: (1) count the total number of tools running the process type of interest (either RPC NF3 or F2 in any process type); (2) count the number of tools running that process type that are equipped with HC fuel CECs that are not certified not to form CF4; and (3) divide (2) by (1). The EPA is revising the final rule to require that reporters must only provide estimates of CF4 emissions from HC fuel CECS purchased and installed on or after January 1, 2025. We recognize that applying the testing, certification, and emissions estimation requirements to older equipment would have expanded the set of equipment for which testing would need to be performed and/or emissions would need to be estimated, which may have posed logistical challenges, particularly for older equipment that may no longer be manufactured. Making the requirements applicable only to HC fuel CECs purchased and installed on or after January 1, 2025 ensures that abatement system manufacturers and/or electronics manufacturers can test the equipment and measure its CF4 generation rate from F2 by March 31, 2026, by which time facilities must either certify that the HC fuel CECS do not generate CF4 or quantify CF4 emissions from the HC fuel CECS. The EPA recognizes that the new requirement to report CF4 emissions from HC fuel CECS could lead to a time series inconsistency in reported emissions. However, such an inconsistency is not in conflict with the overall purpose of the GHGRP to accurately estimate GHG emissions. Nor would it be unique to the electronics industry, because other GHGRP subparts have been revised in ways that altered the time series of the emissions as new source types were added or more accurate methods were adopted. For example, in 2015, subpart W was updated to include a new source, completions and workovers of oil wells with hydraulic fracturing, in the existing Onshore Petroleum and Natural Gas Production segment and also added two entirely new segments, the Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore Natural Gas Transmission Pipelines segments. Such changes in reported emissions are often documented in the public data, including in the EPA’s sector profiles. The EPA is clarifying in this response to comment that equation I–9 is in addition to, rather than in place of, CF4 byproduct factors for RPC NF3, because the CF4 byproduct factors for RPC NF3 E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations represent emissions from the process before abatement, and these emissions were measured without abatement equipment running. Comment: One commenter supported using the term ‘‘hydrocarbon-fuel-based combustion emissions control systems’’ (HC fuel CECS) because it aligns with the nomenclature within 2019 Refinement rather than the less used ‘‘hydrocarbon-fueled abatement systems’’ or other terms. The commenter explained that semiconductor facilities widely implement large, facility-level volatile organic compound abatement devices to eliminate and control criteria volatile and non-volatile organic compounds, with no expectation of fluorinated greenhouse gas emissions. The commenter expressed concern that the broad definition of HC fuel CECS may be interpreted to include all hydrocarbon-based fuel control systems, not just tool-level POU abatement. The commenter added that, although not currently implemented, future facilitylevel F–GHG abatement systems could be incorrectly included in the scope of equation I–9 as it is written. The commenter requested that all emissions control systems language is updated to be consistent. The commenter also specifically requested the definition of ‘‘hydrocarbon-fuel-based combustion emission control systems’’ be tailored to specify HC fuel CECS connected to manufacturing tools, and include the following language: ‘‘and have the potential to emit fluorinated greenhouse gases.’’ Response: The EPA agrees with the commenter and has revised the proposed language to include the term, ‘‘hydrocarbon-fuel-based combustion emissions control systems’’ (HC fuel CECS) to align with the nomenclature within 2019 Refinement. The EPA is also clarifying in the final rule that these requirements apply only to equipment that is connected to manufacturing tools that have the potential to emit F2 or F– GHGs. It is important to include emissions of F2 as well as F–GHGs since it is F2 that may combine with hydrocarbon fuels to generate CF4 emissions. These changes include revising ‘‘hydrocarbon fuel-based emissions control systems’’ to ‘‘HC fuel CECS’’ in the terms ‘‘EABCF4,’’ aF2,j,’’ ‘‘UTF2,j,’’ ‘‘ABCF4,F2,’’ ‘‘aNF3,RPC,’’ ‘‘and ‘‘UTNF3,RPC,F2’’ defined in equation I–9. Comment: One commenter requested the EPA specify that HC fuel CECS uptime during stack testing is ‘‘representative of the emissions stream’’ and the EPA specify that HC fuel CECS uptime during stack testing applies to RPC NF3 or input F2 processes only. The commenter questioned the EPA’s VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 proposed requirement that the uptime during the stack testing period must average at least 90 percent for uncertified hydrocarbon-fueled emissions control systems. The commenters asserted that uptime tracking for uncertified abatement devices is excessive, goes beyond the 2019 Refinement requirements, and does not improve the accuracy of emissions estimates. The commenter requested language to limit this requirement to ‘‘at least 90% uptime of NF3 remote plasma clean HC fuel CECS devices that are not certified to not form CF4 during the test.’’ The commenter also requested EPA clarify that equation I–9 does not apply in addition to stack testing requirements. The commenter requested that CF4 emissions from the HC fuel CECS abatement of F2, as calculated by equation I–9, be specifically exempted from the stack testing method as it would double count CF4 emissions. Response: The EPA agrees with the commenter that it would be helpful to clarify of the applicability of the 90percent uptime requirement for HC fuel CECS. The EPA is revising the rule language at 40 CFR 98.94(j)(1) to further limit the HC fuel CECS 90-percent uptime requirement to systems that were purchased and installed on or after January 1, 2025 and that are used to control emissions from tools that use either NF3 in remote plasma cleaning processes or F2 as an input gas in any process type or sub-type. Either of these input gas-process type combinations may exhaust F2 into HC fuel CECS, potentially leading to the formation of CF4. The qualification ‘‘that are not certified not to form CF4’’ is being finalized as proposed. Regarding the commenters’ concerns related to the uptime tracking requirements for uncertified abatement devices during stack testing, we reiterate that the uptime tracking requirement during stack testing is for hydrocarbonfueled abatement devices that are not certified to not form CF4, because these reporters still need to account for CF4 emissions even if not accounting the abatement device’s F–GHG DRE. The EPA is also clarifying in this response that equation I–9 is not in addition to stack test calculations. The emissions from HC fuel CECS, should they occur, will be captured by the stack testing measurements. Because equation I–9 is not included in or referenced by the stack testing section, the regulatory text in 40 CFR 98.93(i) as currently drafted does not need any additional revision. However, the header paragraph 40 CFR 98.93(a) has been revised to clarify that paragraph (a)(7), which PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 31835 includes equation I–9, is one of the paragraphs used to calculate emissions based on default gas utilization rates and byproduct formations rates. Comment: One commenter objected to the EPA’s proposed calibration requirements for abatement systems, specifically for vacuum pump purge systems. The commenter urged that this would have significant impacts on the semiconductor industry and would drive a major increase in pump replacement and tool downtime. The commenter explained that POU abatement devices and their connected vacuum pumps are separate systems, and while physically connected, POU maintenance and pump replacement schedules are independent of one another. Further, the commenter asserted that pump purge flow calibration is technically and operationally infeasible for device manufacturers to perform. The commenter explained that purge flow indicators are factory calibrated and are part of the pump installation and commissioning; if there is a flow indicator failure, the vacuum pump is replaced with a factory-calibrated pump. The commenter stated that pump maintenance and repair is not typically performed at the manufacturing tool and requires pump disconnection and physical removal, and thus pumps are often repaired off-site. The commenter stressed that pump manufacturers do not provide recommendations or specifications for re-calibration of these pumps. The commenter added that there is no pump redundancy installed on a tool, and to check the calibration and potentially replace the flow transducer, the vacuum pump must be shutdown to safely work on it. The commenter noted that any replacement of the pump would require a tool shutdown and therefore 12 to 48 hours of downtime for manufacturing requalification. The commenter stated that pumps remain continually in service on the order of years and asserted that pump vendors indicate that pumps can remain in service for many years without requiring calibration of the pump purge. The commenter provided that pump changes and refurbishment costs can be over $5,000 per occurrence and noted that pump repair or calibration activities can require significant coordination with factory and site operations due to the highly specialized equipment and resources needed. The commenter estimated that semiconductor manufacturing sites can have 2,000+ POU abatement devices as well as 4,000+ vacuum pumps in a highvolume-manufacturing site. The E:\FR\FM\25APR2.SGM 25APR2 31836 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 commenter subsequently estimated that the EPA’s proposed revisions could result in pump downtime, process equipment tool downtime, and maintenance costs to the U.S. semiconductor industry of about $40 million annually. The commenter also stated that they believe the existing performance certification of POU emissions control devices based on high flow conditions are highly protective of POU system reliability. The commenter reiterated that high flow POU certification is based on maximum device flows, which, for multi-chamber tools, includes all chambers running at once. The commenter urged that significant variations in pump purge flows are unlikely and the magnitude of these variations would be a small component of overall POU flow volumes. As such, the commenter urged that pump purge flows are not necessary to calibrate after initial pump commissioning. Response: The EPA agrees with the commenter that calibration of N2 purge flows is normally done during pump service or maintenance, when the pumps are typically: (1) disconnected from the process tool; (2) replaced by a new or refurbished pump; and (3) brought to a ‘‘service center’’ for refurbishment (sometimes on-site, sometimes off-site). The EPA also concurs with commenters that requiring N2 pump purge calibration could be disruptive if done outside of ‘‘normal’’ service periods. Consequently, the EPA proposed to require that pump purge flow indicators be calibrated ‘‘each time a vacuum pump is serviced or exchanged’’ rather than more frequently. The anticipated frequency of calibration mentioned in the preamble, every six months, was intended to be descriptive rather than prescriptive. Thus, the EPA does not believe that the proposed requirement would have the large economic impacts cited by the commenter. Nevertheless, because it appears that pumps are typically factory calibrated when commissioned and are replaced with factory-calibrated pumps when the flow indicator fails, a calibration requirement is not required. Therefore, the EPA is not taking final action on the proposed calibration requirement. b. Comments on Revisions To Streamline and Improve Implementation for Subpart I Comment: One commenter supported finalizing the amendment to 40 CFR 98.96(y) decreasing the frequency of submission of technology assessment reports, before the due date for the next technology assessment report. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Response: The EPA acknowledges the commenter’s support and is finalizing revisions to 40 CFR 98.96(y) to decrease the frequency of submission of technology assessment reporters to every 5 years, as proposed. However, because the EPA is not implementing the final revisions until January 1, 2025 (see section V. of this preamble), we have revised the provision to clarify that the first technology assessment report due after January 1, 2025 is due on March 31, 2028. Subsequent reports must be submitted every 5 years no later than March 31 of the year in which it is due. H. Subpart N—Glass Production We are finalizing several amendments to subpart N of part 98 (Glass Production) as proposed. The EPA received only supportive comments for the proposed revisions to subpart N. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart N. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart N, as described in section VI. of this preamble. The EPA is finalizing two revisions to the recordkeeping and reporting requirements of subpart N of part 98 (Glass Production) as proposed in the 2022 Data Quality Improvement Proposal. The revisions apply to both CEMS and non-CEMS reporters and require that facilities report and maintain records of annual glass production by glass type (e.g., container, flat glass, fiber glass, specialty glass). Specifically, the final amendments revise (1) 40 CFR 98.146(a)(2) and (b)(3) to require the annual quantity of glass produced in tons, by glass type, from each continuous glass melting furnace and from all furnaces combined; and (2) 40 CFR 98.147(a)(1) and (b)(1), to add that records must also be kept on the basis of glass type. Differences in the composition profile of raw materials, use of recycled material, and other factors lead to differences in emissions from the production of different glass types. Collecting data on the annual quantities of glass produced by type will improve the EPA’s understanding of emissions variations and industry trends, and improve verification for the GHGRP, as well as provide useful information to improve analysis of this sector in the Inventory. The EPA is also PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 finalizing revisions to the recordkeeping and reporting requirements of subpart N as proposed in the 2023 Supplemental Proposal. The final revisions add reporting provisions at 40 CFR 98.146(a)(3) and (b)(4) to require the annual quantity (in tons), by glass type (e.g., container, flat glass, fiber glass, or specialty glass), of cullet charged to each continuous glass melting furnace and in all furnaces combined, and revises 40 CFR 98.146(b)(9) to require the number of times in the reporting year that missing data procedures were used to measure monthly quantities of cullet used. The final revisions also add recordkeeping provisions to 40 CFR 98.147(a)(3) and (b)(3) to require the monthly quantity of cullet (in tons) charged to each continuous glass melting furnace by product type (e.g., container, flat glass, fiber glass, or specialty glass). Differences in the quantities of cullet used in the production of different glass types can lead to variations in emissions, and, due to lower melting temperatures, can reduce the amount of energy and combustion required to produce glass. As such, the annual quantities of cullet used will further improve the EPA’s understanding of variations and differences in emissions estimates, industry trends, and verification, as well as improve analysis for the Inventory. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. I. Subpart P—Hydrogen Production We are finalizing several amendments to subpart P of part 98 (Hydrogen Production) as proposed. In some cases, we are finalizing the proposed amendments with revisions. In other cases, we are not taking final action on the proposed amendments. Section III.I.1. of this preamble discusses the final revisions to subpart P. The EPA received several comments on the proposed subpart P revisions which are discussed in section III.I.2. of this preamble. We are also finalizing related confidentiality determinations for data elements resulting from the revisions to subpart P, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart P This section summarizes the final amendments to subpart P. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other final revisions to 40 CFR part 98, subpart P can be found in this E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 section and section III.I.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Revisions To Improve the Quality of Data Collected for Subpart P In the 2023 Supplemental Proposal, the EPA proposed several amendments to subpart P of part 98 to expand and clarify the source category definition. First, to increase the GHGRP’s coverage of facilities in the hydrogen production sector, we are amending, as proposed, the source category definition in 40 CFR 98.160 to include all facilities that produce hydrogen gas regardless of whether the hydrogen gas is sold. The final revisions will address potential gaps in applicability and reporting, allowing the EPA to better understand and track emissions from facilities that do not sell hydrogen gas to other entities. As proposed, these amendments categorically exempt any process unit for which emissions are currently reported under another subpart of part 98, including, but not necessarily limited to, ammonia production units that report emissions under subpart G of part 98 (Ammonia Manufacturing), catalytic reforming units located at petroleum refineries that produce hydrogen as a byproduct for which emissions are reported under subpart Y of part 98 (Petroleum Refineries), and petrochemical production units that report emissions under subpart X of part 98 (Petrochemical Production). As proposed, we are also exempting process units that only separate out diatomic hydrogen from a gaseous mixture and are not associated with a unit that produces diatomic hydrogen created by transformation of feedstocks. The EPA is also amending the source category definition at 40 CFR 98.160 as proposed to clarify that stationary combustion sources that are part of the hydrogen production unit (e.g., reforming furnaces and hydrogen production process unit heaters) are part of the hydrogen production source category and that their emissions are to be reported under subpart P. These amendments, which include a harmonizing change at 40 CFR 98.162(a), clarify that these furnaces or process heaters are part of the hydrogen production process unit regardless of where the emissions are exhausted (through the same stack or through separate stacks). Similarly, we are finalizing a clarification for hydrogen production units with separate stacks for ‘‘process’’ emissions and VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 ‘‘combustion’’ emission that use a CEMS to quantify emissions from the process emissions stack. The final amendments at 40 CFR 98.163(c) require reporters to calculate and report the CO2 emissions from the hydrogen production unit’s fuel combustion using the mass balance equations (equations P–1 through P–3) in addition to calculating and reporting the process CO2 emissions measured by the CEMS. Additional information on these revisions and their supporting basis may be found in section III.G. of the preamble to the 2023 Supplemental Proposal. We are adding one additional revision to address the monitoring of stationary combustion units directly associated with hydrogen production (e.g., reforming furnaces and hydrogen production process unit heaters), following a review of comments received. Based on the EPA’s analysis of reported data, there may be a small number of reporters that may not currently measure the fuel use to these combustion units separately. We have decided to add new § 98.164(c) to provide the use of best available monitoring methods (BAMM) for those facilities that may still need to install monitoring equipment to measure the fuel used by each stationary combustion unit directly associated with the hydrogen production process unit. To be eligible to use BAMM, the stationary combustion unit must be directly associated with hydrogen production; the unit must not have a measurement device installed as of January 1, 2025; the hydrogen production unit and the stationary combustion unit are operated continuously; and the installation of a measurement device must require a planned process equipment or unit shutdown or only be able to be done through a hot tap. BAMM can be the use of supplier data, engineering calculation methods, or other company records. We are not requiring facilities to provide an application to use BAMM that would require EPA review and approval to measure the fuel used in the hydrogen production process combustion unit. However, we are adding a new requirement at 40 CFR 98.166(d)(10) to require each facility to indicate in their annual report, for each stationary combustion unit directly associated with hydrogen production, whether they are using BAMM, the date they began using BAMM, and the anticipated or actual end date of BAMM use. Providing the use of BAMM is intended to reduce the burden associated with installation of new equipment, and we do not anticipate that the requirement to report the required indicators of BAMM will add significant burden. See section PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 31837 III.I.2. of this preamble for additional information on related comments and the EPA’s response. In the 2022 Data Quality Improvements Proposal, the EPA proposed several amendments to subpart P to allow the subtraction of the mass of carbon contained in products (other than CO2 or methanol) and the carbon contained in intentionally produced methanol from the carbon mass balance used to estimate CO2 emissions. The proposed revisions included new equation P–4 to allow facilities to adjust the calculated emissions from fuel and feedstock consumption in order to calculate net CO2 process emissions, as well as harmonizing revisions to the introductory paragraph of 40 CFR 98.163 and 98.163(b) and the reporting requirements at 40 CFR 98.167(b)(7). Following review of comments received on similar changes proposed for subpart S (Lime Manufacturing), the EPA is not taking final action at this time on the proposed revisions to allow facilities to subtract out carbon contained in products other than CO2 or methanol and the carbon contained in methanol. See sections III.E., III.I.2., and III.K.2. of this preamble for additional information on the comments related to subparts G, P and S and the EPA’s response. However, the EPA is finalizing the proposed reporting requirement at 40 CFR 98.166(b)(7) (now 40 CFR 98.166(d)(7)), with minor revisions as a result of comments received. See the discussion in this section regarding subpart P reporting requirements for additional information as to why EPA is making revisions as a result of comments received. The EPA is finalizing several additional revisions to the subpart P reporting requirements to improve the quality of the data collected based on the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. The final reporting requirements are reorganized to accommodate the final amendments at 40 CFR 98.163(c), which require reporters using CEMS that do not include combustion emissions from the hydrogen production unit to calculate and report the CO2 emissions from fuel combustion using the material balance equations (equations P–1 through P–3) in addition to the process CO2 emissions measured by the CEMS. The revisions to 40 CFR 98.166 clarify the reporting elements that must be provided for each hydrogen production process unit based on the calculation methodologies used. Reporters using CEMS to measure combined CO2 process and fuel combustion emissions will be required E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31838 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations to meet the requirements at 40 CFR 98.166(b); reporters using only the material balance method will be required to meet the requirements at 40 CFR 98.166(c); and reporters using CEMS to measure CO2 process emissions and the material balance method to calculate emissions from fuel combustion emissions using equations P–1 through P–3 will be required to meet the requirements of 40 CFR 98.166(b) and (c). If a common stack CEMS is used to measure emissions from either a common stack for multiple hydrogen production units or a common stack for hydrogen production unit(s) and other source(s), reporters must also report the estimated fraction of CO2 emissions attributable to each hydrogen production process unit. All other reporting requirements for each hydrogen production process unit (regardless of the calculation method) are consolidated under 40 CFR 98.166(d). As proposed, we are finalizing the addition of requirements for facilities to report the process type for each hydrogen production unit (i.e., steam methane reforming (SMR), SMR followed by water gas shift reaction (SMR–WGS), partial oxidation (POX), partial oxidation followed by WGS (POX–WGS), Water Electrolysis, Brine Electrolysis, or Other (specify)), and the purification type for each hydrogen production unit (i.e., pressure swing adsorption (PSA), Amine Adsorption, Membrane Separation, Other (specify), or none); the final requirements have been moved to 40 CFR 98.166(d)(1) and (2) and paragraph (d)(1) has been revised to include ‘‘autothermal reforming only’’ and ‘‘autothermal reforming followed by WGS’’ as additional unit types. We are amending, as proposed, requirements to clarify that the annual quantity of hydrogen produced is the quantity of hydrogen that is produced ‘‘. . . by reforming, gasification, oxidation, reaction, or other transformations of feedstocks,’’ and to add reporting for the annual quantity of hydrogen that is only purified by each hydrogen production unit; the final requirements have been moved to 40 CFR 98.166(d)(3) and (4). We are finalizing a requirement at 40 CFR 98.166(c) (proposed 40 CFR 98.166(b)(5)), to report the name and annual quantity (metric tons (mt)) of each carbon-containing fuel and feedstock (formerly 40 CFR 98.166(b)(7)). For clarity, we have revised the text of the requirement at 40 CFR 98.166(c) from proposal to specify that the information is required whenever equations P–1 through P–3 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 are used to calculate CO2 emissions. We are finalizing revisions that renumber 40 CFR 98.166(c) and (d) (now 40 CFR 98.166(d)(6) and (7)), and are finalizing paragraph (d)(7) with revisions from those proposed to require reporting, on a unit-level: (1) the quantity of CO2 that is collected and transferred off-site; and (2) the quantity of carbon other than CO2 or methanol collected and transferred off-site, or transferred to a separate process unit within the facility for which GHG emissions associated with the carbon is being reported under other provisions of part 98. The final rule also requires at 40 CFR 98.166(d)(9) the reporting of the annual net quantity of steam consumed by the unit (proposed as 40 CFR 98.166(c)(9)). This value will be a positive quantity if the hydrogen production unit is a net steam user (i.e., uses more steam than it produces) and a negative quantity if the hydrogen production unit is a net steam producer (i.e., produces more steam than it uses). Finally, for consistency with the final revisions to the reporting requirements for facilities subject to revised 40 CFR 98.163(c), we are making a harmonizing change to the recordkeeping requirements at 40 CFR 98.167(a) to specify that, if the facility CEMS measures emissions from a common stack for multiple hydrogen production units or emissions from a common stack for hydrogen production unit(s) and other source(s), reporters must maintain records used to estimate the decimal fraction of the total annual CO2 emissions from the CEMS monitoring location attributable to each hydrogen production unit. We are also finalizing as proposed clarifying edits in 40 CFR 98.167(e) that retention of the file required under that provision satisfies the recordkeeping requirements for each hydrogen production unit. See section III.G.1. of the preamble to the 2022 Data Quality Improvements Proposal and section III.G. of the preamble to the 2023 Supplemental Proposal for additional information on these revisions and their supporting basis. In the 2023 Supplemental Proposal, the EPA also requested comment on, but did not propose, other potential revisions to subpart P, including revisions that would remove the 25,000 mtCO2e threshold under 40 CFR 98.2(a)(2), which would result in a requirement that any facility meeting the definition of the hydrogen production category in 40 CFR 98.160 report annual emissions to the GHGRP. The EPA considered these changes in order to collect information on facilities that use electrolysis or other production methods that may have small direct PO 00000 Frm 00038 Fmt 4701 Sfmt 4700 emissions, but that may use relatively large amounts of off-site energy to power the process (i.e., the emissions occurring on-site at these hydrogen production facilities may fall below the existing applicability threshold, while the combined direct emissions (i.e., ‘‘scope 1’’ emissions) and emissions attributable to energy consumption (i.e., ‘‘scope 2’’ emissions) could be relatively large), as collecting information from these kinds of facilities as well is especially important in understanding hydrogen as a fuel source. To reduce the burden on small producers, the EPA requested comment on applying a minimum annual production quantity within the source category definition to limit the applicability of the source category to larger hydrogen production facilities, such as defining the source category to only include those hydrogen production processes that exceed a 2,500 metric ton (mt) hydrogen production threshold. The EPA also requested comment on potential options to require continued reporting from hydrogen production facilities that use electrolysis or other production methods that may have small direct emissions (i.e., scope 1 emissions) that would likely qualify to cease reporting after three to five years under the part 98 ‘‘off-ramp’’ provisions of 40 CFR 98.2(i) (i.e., facilities may stop reporting after three years if their emissions are under 15,000 mtCO2e or after five years if their emissions are between 15,000 and 25,000 mtCO2e), to enable collection of a more comprehensive data set over time. Following consideration of comments received, the EPA is not taking final action on these potential revisions in this rule. See section III.I.2. of this preamble for additional information on related comments and the EPA’s responses. The EPA also considered, but did not propose, further expanding the reporting requirements to include the quantity of hydrogen provided to each end-user (including both on-site use and delivered hydrogen) and, if the end-user reports to GHGRP, the e-GGRT identifier for that customer. The EPA requested comment on the approach to collecting this sales information and the burden such a requirement may impose in the 2023 Supplemental Proposal. Following review of comments received, the EPA is not taking final action on these potential revisions in this rule. b. Revisions To Streamline and Improve Implementation for Subpart P The EPA is finalizing several revisions to subpart P to streamline the requirements of this subpart and improve flexibility for reporters. To E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations address the recent use of low carbon content feedstocks, the EPA is finalizing, with revisions from those proposed, revisions to 40 CFR 98.164(b)(2) and (3) to allow the use of product specification information annually as specified in the final provisions for (1) gaseous fuels and feedstocks that have carbon content less than or equal to 20 parts per million by weight (i.e., 0.00002 kg carbon per kg of gaseous fuel or feedstock) (rather than at least weekly sampling and analysis), and (2) for liquid fuels and feedstocks that have a carbon content of less than or equal to 0.00006 kg carbon per gallon of liquid fuel or feedstock (rather than monthly sampling and analysis). As explained in the 2022 Data Quality Improvements Proposal, the fuels and feedstocks below these concentrations have very limited GHG emission potential and are currently an insignificant contribution to the GHG emissions from hydrogen production. The revisions from those proposed were included to remove the term ‘‘nonhydrocarbon’’ because it is not necessary since the maximum hydrocarbon concentrations that qualify for the revised monitoring requirements are included in 40 CFR 98.164(b)(2) and (3). The EPA is finalizing, with revisions from those proposed, the addition of new 40 CFR 98.164(b)(5)(xix) to allow the use of modifications of the methods listed in 40 CFR 98.164(b)(5)(i) through (xviii) or use of other methods that are applicable to the fuel or feedstock if the methods currently in 40 CFR 98.164(b)(5) are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe. The revisions from those proposed were harmonizing changes to remove the term ‘‘non-hydrocarbon’’ and tie the proposed revisions back more clearly to the specifications in paragraphs (b)(2) and (3). The final rule also finalizes as proposed, revisions to § 98.164(b)(2) through (4) to specifically state that the carbon content must be determined ‘‘. . . using the applicable methods in paragraph (b)(5) of this section’’ to clarify the linkage between the requirements in § 98.164(b)(2) through (4) and § 98.164(b)(5). Finally, the EPA is finalizing revisions to the recordkeeping requirements at 40 CFR 98.167(b) to refer to paragraph (b) of 40 CFR 98.166. For facilities using the alternatives at 40 CFR 98.164(b)(2), (3) or (5)(xix), these requirements include retention of product specification sheets, records of VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 modifications to the methods listed in 40 CFR 98.164(b)(5)(i) through (xviii) that are used, and records of the alternative methods used, as applicable. We are also finalizing a revision to remove and reserve redundant recordkeeping requirements in 40 CFR 98.167(c). See section III.G.2. of the preamble to the 2022 Data Quality Improvements Proposal and section III.G. of the preamble to the 2023 Supplemental Proposal for additional information on these revisions and their supporting basis. 2. Summary of Comments and Responses on Subpart P This section summarizes the major comments and responses related to the proposed amendments to subpart P. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart P. Comment: Two commenters recommended expanding the source category to include all hydrogen production facilities; this would include non-merchant producers, facilities that use electrolysis or renewable energy, and include process units that do not report to other subparts. Other commenters did not oppose expanding the source category to non-merchant facilities. One commenter on the 2022 Data Quality Improvements Proposal stated that the existing definition may cause confusion in situations where the hydrogen produced is used on-site or otherwise not ‘‘sold as a product to other entities’’ and suggested specific revisions to expand the source category to include other types of hydrogen production plants, including those using electrolysis. One commenter stated that reporting energy consumption by hydrogen production sources is necessary to inform decarbonization strategies, e.g., whether producing excessive amounts of green hydrogen may risk delaying fossil fuel retirement by diverting renewable energy from other uses. The commenter recommended a threshold for these facilities based on energy input. The commenter added that any hydrogen production facilities using carbon capture and sequestration technology should be required to report in all instances, as emissions data and energy consumption data from these facilities will be highly relevant to future regulatory action. PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 31839 Multiple commenters commented on the EPA’s request for comment regarding removing the threshold for the hydrogen production source category. One commenter strongly urged the EPA to make subpart P an ‘‘all-in’’ subpart to ensure all hydrogen production facilities are covered by reporting requirements, including the requirements proposed to report purchased energy consumption under proposed subpart B to part 98. The commenter pointed to hydrogen electrolysis facilities that may consume very large amounts of grid electricity that could have significant upstream emissions impacts; the commenter stated that many or most of these facilities will already be tracking the attributes of the energy they consume to qualify for Federal incentives and investment, and will therefore have this information readily available. The commenter stressed that understanding this information and the lifecycle emissions of hydrogen production will be critical to informing future actions under the CAA. The commenter also supported a production-based reporting threshold to ensure reporting for high production facilities with lower direct emissions and suggested the production threshold should at least include at least the top 75 percent of production facilities. One commenter suggested a hydrogen production threshold of 5,000 mt/year. Another commenter recommended that the EPA should implement a threshold to limit the applicability of the subpart to larger hydrogen production facilities. One commenter opposed a hydrogen production threshold, and recommended that the EPA retain the existing emissions-based threshold of 25,000 mtCO2e; the commenter suggested this would further incentivize the implementation of low GHG hydrogen manufacturing processes over higher emitting processes such as steam methane reformers. Several commenters also opposed revisions that would remove the ability of sources to off-ramp. One commenter offered the following recommendations: (1) hydrogen production process units which produce hydrogen but emit no direct GHG emissions should become eligible to cease reporting starting January 1 of the following year after the cessation of direct GHG emitting activities associated with the process; (2) if the direct GHG emissions remain below 15,000 mtCO2e or between 15,000 and 25,000 mtCO2e, reporting would be required for 3 or 5 years respectively, consistent with the existing off-ramp provisions; or (3) if the EPA establishes E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31840 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations a hydrogen production threshold for reporting, then falling below the production threshold should be the trigger for cessation of reporting, either starting January 1 of the following year or on a parallel structure to the three and five year off-ramp emission thresholds. Two other commenters stated that the EPA ignores that the ‘‘offramp’’ is intended for entities that should no longer be subject to reporting requirements by virtue of the fact that their emissions fall below a reasonable threshold. One commenter stated that it is unclear how the EPA would have authority to continue to require reporting for these entities, and the commenters said that the EPA should justify excluding hydrogen production facilities from the off-ramp. The commenters added that the EPA could use other methods to collect this data, including proposing a separate standard addressing emissions from hydrogen production under CAA section 111. Response: We agreed with commenters that the language regarding ‘‘hydrogen gas sold as a product to other entities’’ could cause confusion, as we intended to require non-merchant hydrogen production units to now report under subpart P. As such, we are finalizing, as proposed in the 2023 Supplemental Proposal, the language in 40 CFR 98.160(a) to focus on hydrogen gas production without referring to the disposition of the hydrogen produced. In the 2023 Supplemental Proposal, we also proposed to significantly revise § 98.160(b) and (c). The supplemental proposal revisions appear to address most of the commenter’s suggested revisions, except that we are not including ‘‘electrolysis’’ in the list of types of transformations in 40 CFR 98.160(b) because we consider electrolysis as already included under ‘‘. . . reaction, or other transformations of feedstocks.’’ This is also supported by the inclusion of water electrolysis and brine electrolysis in the list of hydrogen production unit types in the proposed 40 CFR 98.166(b)(1)(i) (now 40 CFR 98.166(d)(1)). We agree with commenters that subpart P should be applicable to non-merchant facilities and are finalizing the proposed revisions. The EPA has considered comments both supporting and not supporting changes related to the EPA’s request for information regarding removing the emissions-based threshold or introducing an alternative productionbased threshold for the hydrogen production source category, including options to require continued reporting from hydrogen production facilities by amending the emissions-based off-ramp VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 provisions at 40 CFR 98.2(i)(1) and (2). The EPA did not propose or provide for review specific revisions to part 98 to expand the source category, beyond the inclusion of non-merchant facilities as discussed in section III.I.1. of this preamble. Therefore, we are not including any revisions to the threshold to subpart P or to the ability of hydrogen production facilities to off-ramp in this final rule. However, the EPA may further consider these comments and the information provided as we evaluate next steps concerning the collection of information from hydrogen production facilities and consider approaches to improving our understanding of hydrogen as a fuel source, including to inform any potential future rulemakings. Comment: Three commenters did not support the requirement to report combustion from hydrogen production process units under subpart P in lieu of subpart C as proposed in 40 CFR 98.160(c). Two commenters stated that these units may not be metered separately from other combustion units located at an integrated facility, which would require additional metering to comply with subpart P reporting of combustion emissions directly associated with the hydrogen production process. These commenters stated that if combustion emissions directly associated with the hydrogen production process must be reported under subpart P, engineering estimations for fuel consumption should be allowed. One commenter recommended that EPA implement a threshold to limit the applicability of the subpart to larger hydrogen production facilities. Response: Steam methane reforming (SMR) is an endothermic process, and heating and reheating of fuels and feedstocks to maintain reaction temperatures is an integral part of the steam methane reforming reaction. Therefore, subpart P has always required the reporting of ‘‘fuels and feedstocks’’ used in the hydrogen production unit and subpart C should only be used for ‘‘. . . each stationary combustion unit other than hydrogen production process units’’ (40 CFR 98.162(c)). We have long noted that the emissions from most SMR furnaces include a mixture of process and combustion emissions.15 For more accurate comparison of CEMS measured emissions with those estimated using the mass balance method, we required reporting of the combustion emissions from the SMR furnace as part of the 15 See, e.g., https://ccdsupport.com/confluence/ pages/viewpage.action?pageId=173080691. PO 00000 Frm 00040 Fmt 4701 Sfmt 4700 subpart P emissions. Our proposed revisions, therefore, were not a new requirement, but a further clarification of the existing requirements in subpart P, as we interpret them. Based on previous reviews of the emissions intensities from hydrogen production as compiled from subpart P reported data, we estimate that there are only a few facilities that do not include the SMR furnace or process heaters combustion emissions in their subpart P emission totals. To allow time for those facilities to measure fuel used in stationary combustion units associated with hydrogen production (e.g., reforming furnaces and hydrogen production process unit heaters), we decided to include in this final rule a limited allowance for BAMM for those facilities that may still need to add appropriate monitoring equipment (as demonstrated through meeting the specified criteria in the final provision). We also note that subpart C units reporting under the common pipe reporting configuration at 40 CFR 98.36(c)(3) may use company records to subtract out the portion of the fuel diverted to other combustion unit(s) prior to performing the GHG emissions calculations for the group of units using the common pipe option. Regarding the recommendation to implement a threshold to limit applicability to larger hydrogen production facilities, we are not taking final action on any revisions to the threshold to subpart P, therefore, facilities with hydrogen production plants will continue to determine applicability to part 98 based on the existing requirements of 40 CFR 98.2(a). A facility that contains a source category listed in table A–4 to subpart A of part 98 (which includes hydrogen production) must report only if the estimated combined annual emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all applicable source categories in tables A– 3 and table A–4 of part 98 are 25,000 mtCO2e or more. Therefore, the applicability of the subpart is already limited to larger hydrogen production facilities. Comment: One commenter stated that EPA’s proposed mass balance equation under 40 CFR 98.163(d), equation P–4, requires further revision to ensure that it is accurate for refineries that have non-merchant hydrogen plants (such as those currently reporting under subpart Y). The commenter added that to ensure proper accounting, the variable ‘‘Coftsite,n’’ should be further revised to include language for non-merchant hydrogen plants as follows: ‘‘Mass of carbon other than CO2 or methanol collected from the hydrogen production E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations unit and transferred off site or reported elsewhere by the facility under this part, from company records for month n (metric tons carbon).’’ Response: Following consideration of comments on similar proposed revisions in other subparts, as discussed in section III.K.2. of this preamble, we are not taking final action at this time on proposed amendments to equation P–4 to allow the subtraction of carbon contained in products other than CO2 or methanol and the carbon contained in methanol from the carbon mass balance used to estimate CO2 emissions. However, we acknowledge this concern and agree that an analogous scenario may also occur within a facility that contains a captive (non-merchant) hydrogen production process unit. For example, some hydrogen production processes may operate without the water-gas-shift reaction and produce a syngas of hydrogen and carbon monoxide. For merchant plants, this syngas would be sold as a product for use as a fuel or as a feedstock for chemical production process. For a nonmerchant plant, the syngas may be used on-site as a fuel or feedstock rather than sold off-site as a product. If a captive hydrogen production unit produces syngas for use as a fuel for an on-site stationary combustion unit, for example, the rule as proposed would not have allowed the subtraction of the carbon in the syngas from the emissions from the hydrogen production unit, resulting in double counting the CO2 emissions related to this carbon (from both the hydrogen production unit and from the stationary combustion source). Most refineries with captive hydrogen production units seek to produce hydrogen for use in their refining process units and, therefore, use the water-gas-shift reaction to make pure hydrogen rather than syngas. However, production of syngas is possible under some circumstances. Although we are not finalizing equation P–4 as proposed, because the rule currently requires the reporting of carbon other than CO2 or methanol that is transferred off site, we have revised the reporting requirements to clarify that the reported value, for non-merchant hydrogen production facilities, should include the quantity of carbon other than CO2 or methanol that is transferred to a separate process unit within the facility for which GHG emissions associated with this carbon are being reported under other provisions of part 98. Comment: One commenter supported the separate reporting of hydrogen that is produced and hydrogen that is only purified, but requested that the EPA provide sufficient implementation time VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 and allow for best available monitoring methods to be used until installation of necessary monitoring equipment could occur. Another commenter was supportive of reporting steam consumption data (i.e., annual net quantity of steam consumed). However, the commenter added that there may be situations where steam is sourced from equipment (e.g., a stand-alone boiler) distinct from a waste heat boiler associated with the SMR process; the commenter stated the rule should allow for flexibility in how the steam production and consumption is measured and quantified, including the ability to utilize best available monitoring methods. Other commenters opposed reporting steam consumption data. One commenter opposing the requirements stated it could result in duplicative reporting based on what is proposed to be reported under subpart B. Two commenters stated that the EPA failed to provide justification for the requirement. Two commenters stated that it may be necessary for the EPA to issue an additional supplemental notice of proposed rulemaking to take comment on any such justification. Response: Subpart P only provides monitoring requirements for fuels and feedstocks, it does not specify monitoring requirements for other reported data, for example, ammonia and methanol production. There are often cases in part 98 where there are reporting elements, but not specific monitoring requirements. In such cases, company records, engineering estimates, and similar approaches may be used (in addition to direct measurement methods) to report these quantities. As such, there is no need for BAMM provisions related to additional reporting requirements that require separately reporting produced and purified hydrogen quantities and net steam consumption. We also note that the subpart P requirement is process unit specific, which is not duplicative of the proposed subpart B facility- or subpart-level reporting requirements. We also disagree that we did not provide rationale for the proposed requirements. These requirements (as with many of the other proposed requirements for subpart P) are aimed to obtain better information to verify reported emissions. For example, if a facility is a net steam purchaser, some emissions resulting from activities that support the hydrogen production process may occur at the steam production site. Thus, knowing the net steam consumption may help explain why the emissions to production ratios for these facilities PO 00000 Frm 00041 Fmt 4701 Sfmt 4700 31841 based on reported data do not fall within the expected ranges. Understanding this could result in less correspondence from the EPA to verify these facilities’ reports and therefore reduce the burden to these facilities. J. Subpart Q—Iron and Steel Production We are finalizing the amendments to subpart Q of part 98 (Iron and Steel Production) as proposed. This section discusses the final revisions to subpart Q. The EPA received comments on the proposed requirements for subpart Q; see the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart Q. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the revisions to subpart Q as described in section VI. of this preamble. 1. Revisions To Improve the Quality of Data Collected for Subpart Q The EPA is finalizing revisions to subpart Q, as proposed in the 2022 Data Quality Improvements Proposal, to enhance the quality and accuracy of the data collected. First, we are revising 40 CFR 98.176(g) for all unit types (taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, and direct reduction furnace) and all calculation methods (direct measurement using CEMS, carbon mass balance methodologies, or site-specific emission factors) to require that facilities report the type of unit, the annual production capacity, and the annual operating hours for each unit. The EPA is also finalizing revisions to correct equation Q–5 in 40 CFR 98.173(b)(1)(v) to remove an error introduced into the equation in prior revisions (81 FR 89188, December 9, 2016). The final rule corrects the equation to remove an unnecessary fraction symbol. See section III.H.1. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. 2. Revisions To Streamline and Improve Implementation for Subpart Q The EPA is finalizing two revisions to subpart Q to streamline monitoring. First, we are revising 40 CFR E:\FR\FM\25APR2.SGM 25APR2 31842 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 98.174(b)(2) to provide the option for facilities to determine the carbon content of process inputs and outputs by use of analyses provided by material recyclers that manage process outputs for sale or use by other industries. Material recyclers conduct testing on their inputs and products to provide to entities using the materials downstream, and therefore perform carbon content analyses using similar test methods and procedures as suppliers. The final revisions include a minor harmonizing change to 40 CFR 98.176(e)(2) to require reporters to indicate if the carbon content was determined from information supplied by a material recycler. The EPA is also finalizing revisions to 40 CFR 98.174(b)(2) to incorporate a new test method, ASTM E415–17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (2017), for carbon content analysis of low-alloy steel. The new method is incorporated by reference in 40 CFR 98.7 and 98.174(b)(2) for use for steel, as applicable. The addition of this alternative test method will provide additional flexibility for reporters. We are also finalizing one harmonizing change to the reporting requirements of 40 CFR 98.176(e)(2), to clarify that the carbon content analysis methods available to report are those methods listed in 40 CFR 98.174(b)(2). See section III.H.2. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. lotter on DSK11XQN23PROD with RULES2 K. Subpart S—Lime Production We are finalizing several amendments to subpart S of part 98 (Lime Production) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.K.1. of this preamble discusses the final revisions to subpart S. The EPA received several comments on the proposed subpart S revisions which are discussed in section III.K.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart S, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart S The EPA is finalizing several revisions to subpart S of part 98 (Lime Manufacturing) as proposed to improve the quality of the data collected from this subpart. First, we are finalizing the addition of reporting requirements for VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 reporters using the CEMS methodology, in order to improve our understanding of source category emissions and our ability to verify reported data. The EPA is adding data elements under 40 CFR 98.196(a) to collect annual averages of the chemical composition input data on a facility-basis, including the annual arithmetic average calcium oxide content (mt CaO/mt tons lime) and magnesium oxide content (mt MgO/mt lime) for each type of lime produced, for each type of calcined lime byproduct and waste sold, and for each type of calcined lime byproduct and waste not sold. These data elements rely on an arithmetic average of the measurements rather than requiring reporters to weight by quantities produced in each month. Collecting average chemical composition data for CEMS facilities will provide the EPA the ability to develop a process emission estimation methodology for CEMS reporters, which can be used to verify the accuracy of the reported CEMS emission data. The EPA is also finalizing additional data elements for reporters using the mass balance methodology (i.e., reporters that comply using the requirements at 40 CFR 98.193(b)(2)). The final rule includes new data elements under 40 CFR 98.196(b) to collect the annual average results of the chemical composition analysis of all lime byproducts or wastes not sold (e.g., a single facility average calcium oxide content calculated from the calcium oxide content of all lime byproduct types at the facility), and the annual quantity of all lime byproducts or wastes not sold (e.g., a single facility total calculated as the sum of all quantities, in tons, of all lime byproducts at the facility not sold during the year). These amendments will allow the EPA to build verification checks for the actual inputs entered (e.g., MgO content). Because the final data elements rely on annual averages of the chemical composition measurements and an annual quantity of all lime byproducts or wastes at the facility, they are distinct from the data entered into the EPA’s verification software tool. Additional information on these revisions and their supporting basis may be found in section III.I. of the preamble to the 2022 Data Quality Improvements Proposal. In the 2022 Data Quality Improvements Proposal, the EPA proposed to improve the methodology for calculation of annual CO2 process emissions from lime production to account for CO2 that is captured from lime kilns and used on-site. Specifically, we proposed to modify equation S–4 to subtract the CO2 that is PO 00000 Frm 00042 Fmt 4701 Sfmt 4700 captured and used in on-site processes, with corresponding revisions to the recordkeeping requirements in 40 CFR 98.197(c) (to record the monthly amount of CO2 from the lime manufacturing process that is captured for use in all on-site processes), minor amendments to the reporting elements in 40 CFR 98.196(b)(1) (to clarify reporting of annual net emissions), 40 CFR 98.196(b)(17) (to clarify reporters do not need to account for CO2 that was not captured but was used on-site), and to clarify that reporters must account for CO2 usage from all on-site processes, including for manufacture of other products, in the total annual amount of CO2 captured. Following consideration of comments received, the EPA is not taking final action at this time on the proposed revisions to equation S–4, or the corresponding revisions to 40 CFR 98.196(b)(1) and 98.197(c). We are finalizing the clarifying revisions to 40 CFR 98.196(b)(17), as proposed. We are also finalizing an editorial correction to equation S–4 to add a missing equation symbol. See section III.K.2. of this preamble for additional information on related comments and the EPA’s response. 2. Summary of Comments and Responses on Subpart S This section summarizes the major comments and responses related to the proposed amendments to subpart S. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart S. Comment: One commenter opposed the proposed modifications to equation S–4 requiring monthly subtraction of CO2 used on-site, stating it would be considerably more burdensome for lime producers that currently track and report this usage on an annual basis. The commenter requested that the EPA continue to allow the annual reporting of CO2 usage, and thus implement an annual subtraction from total process emissions from all lime kilns combined. Response: The EPA proposed revisions to subparts G (Ammonia Manufacturing), P (Hydrogen Production), and S (Lime Manufacturing) that would have required monthly measurement of captured CO2 used to manufacture other products on-site or non-CO2 carbon sent off-site to external users. It would also have modified the subpart-level equations to require that these amounts E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations be subtracted from the emissions total. However, the EPA needs additional time to consider these comments and whether a consistent approach across these three subparts should be required or whether there are circumstances where alternative approaches might be warranted. Therefore, the EPA is not taking final action on these proposed revisions to subparts G, P, and S for at this time but may consider implementing these or similar revisions in future rulemakings. lotter on DSK11XQN23PROD with RULES2 L. Subpart U—Miscellaneous Uses of Carbonate The EPA is finalizing one minor change to subpart U of part 98 (Miscellaneous Uses of Carbonate). The revision in this final rule is a harmonizing change following review of comments received on proposed subpart ZZ to part 98 (Ceramics Manufacturing) (see section III.EE. of this preamble for additional information on the related comments and the EPA’s response). We are revising the source category definition for subpart U at 40 CFR 98.210(b) to clarify that ceramics manufacturing is excluded from the source category. Section 98.210(b) excludes equipment that uses carbonates or carbonate-containing materials that are consumed in production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, or zinc. We are adding the text ‘‘or ceramics’’ to ensure that there is no duplicative reporting between subpart U and new subpart ZZ. M. Subpart X—Petrochemical Production We are finalizing several amendments to subpart X of part 98 (Petrochemical Production) as proposed. This section summarizes the final revisions to subpart X. The EPA received only minor comments on the proposed requirements for subpart X. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart X. We are finalizing as proposed several amendments to subpart X to improve the quality of data reported and to clarify the calculation, recordkeeping, and reporting requirements. First, we are finalizing a clarification to the emissions calculation requirements for flares in 40 CFR 98.243(b)(3) and (d)(5) VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 to cross-reference 40 CFR 98.253(b) of subpart Y; these revisions clarify that subpart X reporters are not required to report emissions from combustion of pilot gas and from gas released during startup, shutdown, and malfunction (SSM) events of <500,000 standard cubic feet (scf)/day that are excluded from equation Y–3. Next, we are finalizing as proposed the addition of new reporting requirements intended to improve the quality of the data collected under the GHGRP. First, we are finalizing reporting a new data element in 40 CFR 98.246(b)(7) and (c)(3). For each flare that is reported under the CEMS and optional ethylene combustion methodologies, facilities must report the estimated fractions of the total CO2, CH4, and N2O emissions from each flare that are due to combusting petrochemical off-gas. The final rule will allow the fractions attributed to each petrochemical process unit that routes emissions to the flare to be estimated using engineering judgment. This change will allow more accurate quantification of emissions both from individual petrochemical process units and from the industry sector as a whole. Next, the EPA is finalizing addition of a requirement in 40 CFR 98.246(c)(6) to report the names and annual quantity (in metric tons) of each product produced in each ethylene production process for emissions estimated using the optional ethylene combustion methodology; this improves consistency with the product reporting requirements under the CEMS and mass balance reporting options. We are finalizing, as proposed, a number of amendments that are intended to remove redundant or overlapping requirements and to clarify the data to be reported, as follows: • For facilities that use the mass balance approach, we are finalizing amendments to 40 CFR 98.246(a)(2) to remove the requirement to report feedstock and product names, which previously overlapped with reporting requirements in 40 CFR 98.246(a)(12) and (13). • We are finalizing revisions to 40 CFR 98.246(a)(5) to clarify the petrochemical and product reporting requirements for integrated ethylene dichloride/vinyl chloride monomer (EDC/VCM) process units. The amendments clarify the rule for facilities with an integrated EDC/VCM process unit that withdraw small amounts of the EDC as a separate product stream. The final rule is revised at 40 CFR 98.246(a)(5) to specify that (1) the portion of the total amount of EDC produced that is an intermediate in the PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 31843 production of VCM may be either a measured quantity or an estimate; (2) the amount of EDC withdrawn from the process unit as a separate product (i.e., the portion of EDC produced that is not utilized in the VCM production) is to be measured in accordance with 40 CFR 98.243(b)(2) or (3); and (3) the sum of the two values is to be reported under 40 CFR 98.246(a)(5) as the total quantity of EDC petrochemical from an integrated EDC/VCM process unit. • We are finalizing a change in 40 CFR 98.246(a)(13) to clarify that the amount of EDC product to report from an integrated EDC/VCM process unit should be only the amount of EDC, if any, that is withdrawn from the integrated process unit and not used in the VCM production portion of the integrated process unit. • For facilities that use CEMS, we are finalizing amendments to 40 CFR 98.246(b)(8) to clarify the reporting requirements for the amount of EDC petrochemical when using an integrated EDC/VCM process unit, by removing language related to considering the petrochemical process unit to be the entire integrated EDC/VCM process unit. • For facilities that use the optional ethylene combustion methodology to determine emissions from ethylene production process units, we are finalizing revisions to 40 CFR 98.246(c)(4) to clarify that the names and annual quantities of feedstocks that must be reported will be limited to feedstocks that contain carbon. • We are finalizing changes to 40 CFR 98.246(a)(15) to more clearly specify that molecular weight must be reported for gaseous feedstocks and products only when the quantity of the gaseous feedstock or product used in equation X–1 is in standard cubic feet; the molecular weight does not need to be reported when the quantity of the gaseous feedstock or product is in kilograms. Additional information on the EPA’s rationale for these revisions may be found in section III.K. of the preamble to the 2022 Data Quality Improvements Proposal. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the revisions to subpart X, as described in section VI. of this preamble. N. Subpart Y—Petroleum Refineries We are finalizing several amendments to subpart Y of part 98 (Petroleum Refineries) as proposed. This section summarizes the final revisions to subpart Y. The EPA received several comment letters on the proposed E:\FR\FM\25APR2.SGM 25APR2 31844 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 requirements for subpart Y. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart Y. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the revisions to subpart Y, as described in section VI. of this preamble. 1. Revisions To Improve the Quality of Data Collected for Subpart Y The EPA is finalizing as proposed several amendments to subpart Y of part 98 to improve data collection, clarify rule requirements, and correct an error in the rule. First, we are finalizing amendments to the provisions for delayed coking units (DCU) to add reporting requirements for facilities using mass measurements from company records to estimate the amount of dry coke at the end of the coking cycle in 40 CFR 98.256(k)(6)(i) and (ii). These new paragraphs will require facilities to additionally report, for each DCU: (1) the internal height of the DCU vessel; and (2) the typical distance from the top of the DCU vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet). These new elements will allow the EPA to estimate and verify the reported mass of dry coke at the end of the cooling cycle as well as the reported DCU emissions. We are also finalizing revisions to equation Y–18b in 40 CFR 98.253(i)(2), to include a new variable ‘‘fcoke’’ to allow facilities that do not completely cover the coke bed with water prior to venting or draining to accurately estimate the mass of water in the drum. The ‘‘fcoke’’ variable is defined as the fraction of coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining, where a value of one (1) represents cases where the coke is completely submerged in water. The second term in equation Y–18b represents the volume of coke in the drum, and is subtracted from the waterfilled coke bed volume to determine the volume of water. We are also finalizing revisions to the equation terms ‘‘Mwater’’ and ‘‘Hwater’’ to add the phase ‘‘or draining’’ to specify that these parameters reflect the mass of water and the height of water, respectively, at the end of the cooling cycle just prior to atmospheric venting or draining. We are finalizing harmonizing revisions to the recordkeeping requirements at 40 CFR VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 98.257(b)(45) and (46) and a corresponding recordkeeping requirement at 40 CFR 98.257(b)(53). To help clarify that the calculation methodologies in 40 CFR 98.253(c) and 98.253(e) are specific to coke burn-off emissions, we are finalizing the addition of ‘‘from coke burn-off’’ immediately after the first occurrence of ‘‘emissions’’ in the introductory text of 40 CFR 98.253(c) and 98.253(e). We are also finalizing corrections to an inconsistency inadvertently introduced into subpart Y by amendments published on December 9, 2016 (81 FR 89188), which created an apparent inconsistency about whether to include or exclude SSM events less than 500,000 scf/day in equation Y–3. This final rule clarifies in 40 CFR 98.253(b) that SSM events less than 500,000 scf/day may be excluded, but only if reporters are using the calculation method in 40 CFR 98.253(b)(1)(iii). We are also finalizing revisions to remove the recordkeeping requirements in existing 40 CFR 98.257(b)(53) through (56) and to reserve 40 CFR 98.257(b)(54) through (56). These requirements should have been removed in the December 9, 2016 amendments, which removed the corresponding requirement in 40 CFR 98.253(j) to calculate CH4 emissions from DCUs using the process vent method (equation Y–19). The EPA is also finalizing corrections to an erroneous cross-reference in 40 CFR 98.253(i)(5), which inaccurately defines the term ‘‘Mstream’’ in equation Y–18f for DCUs, to correct the cross-reference to § 98.253(i)(4) instead of § 98.253(i)(3). Additional information on the EPA’s rationale for these revisions may be found in section III.L.1. of the preamble to the 2022 Data Quality Improvements Proposal. The EPA is finalizing as proposed one additional revision to improve data quality from the 2023 Supplemental Proposal. Specifically, we are finalizing the addition of a requirement to report the capacity of each asphalt blowing unit, consistent with the existing reporting requirements for other emissions units under subpart Y. The final rule requires that facilities provide the maximum rated unit-level capacity of the asphalt blowing unit, measured in mt of asphalt per day, in 40 CFR 98.256(j)(2). Additional information on the EPA’s rationale for these revisions may be found in section III.H. of the preamble to the 2023 Supplemental Proposal. PO 00000 Frm 00044 Fmt 4701 Sfmt 4700 2. Revisions To Streamline and Improve Implementation for Subpart Y The EPA is finalizing one change to subpart Y to streamline monitoring. We are finalizing an option for reporters to use mass spectrometer analyzers to determine gas composition and molecular weight without the use of a gas chromatograph. The final rule adds the inclusion of direct mass spectrometer analysis as an allowable gas composition method in 40 CFR 98.254(d). This change will allow reporters to use the same analyzers used for process control or for compliance with continuous sampling which are proposed to be provided under the National Emissions Standards for Hazardous Air Pollutants from Petroleum Refineries (40 CFR part 63, subpart CC), to comply with GHGRP requirements in subpart Y. Additional information on these revisions and their supporting basis may be found in section III.L.2. of the preamble to the 2022 Data Quality Improvements Proposal. Consistent with changes we are finalizing to subpart P of part 98 (Hydrogen Production) from the 2023 Supplemental Proposal, we are finalizing revisions to remove references to non-merchant hydrogen production plants in 40 CFR 98.250(c) and to delete and reserve 40 CFR 98.252(i), 98.255(d), and 98.256(b). We are also finalizing as proposed revisions to remove references to coke calcining units in 40 CFR 98.250(c) and 98.257(b)(16) through (19) and to remove and reserve 40 CFR 98.252(e), 98.253(g), 98.254(h), 98.254(i), 98.256(i), and 98.257(b)(27) through (31). As proposed in the 2023 Supplemental Proposal, we are finalizing the addition of new subpart WW to part 98 (Coke Calciners), and these provisions are no longer necessary under subpart Y. Additional information on these revisions and their supporting basis may be found in section III.H. of the preamble to the 2023 Supplemental Proposal. O. Subpart AA—Pulp and Paper Manufacturing We are finalizing the amendments to subpart AA of part 98 (Pulp and Paper Manufacturing) as proposed. The EPA received no comments regarding the proposed revisions to subpart AA. Additional rationale for these amendments is available in the preamble to the 2023 Supplemental Proposal. The EPA is revising 40 CFR 98.273 to add a biogenic calculation methodology for estimation of CH4, N2O, and biogenic CO2 emissions for units that combust biomass fuels (other E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations than spent liquor solids) from table C– 1 to subpart C of part 98 or that combust biomass fuels (other than spent liquor solids) with other fuels. We are also revising 40 CFR 98.276(a) to remove incorrect references to biogenic CH4 and N2O and correcting a typographical error at 40 CFR 98.277(d), as proposed. Additional rationale for these amendments is available in the preamble to the 2023 Supplemental Proposal. lotter on DSK11XQN23PROD with RULES2 P. Subpart BB—Silicon Carbide Production We are finalizing the amendments to subpart BB of part 98 (Silicon Carbide Production) as proposed. The EPA received no comments regarding the proposed revisions to subpart BB. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. The EPA is finalizing a reporting requirement at 40 CFR 98.286(c) such that if CH4 abatement technology is used at silicon carbide production facilities, then facilities must report: (1) the type of CH4 abatement technology used and the date of installation for each technology; (2) the CH4 destruction efficiency (percent destruction) for each CH4 abatement technology; and (3) the percentage of annual operating hours that CH4 abatement technology was in use for all silicon carbide process units or production furnaces combined. For each CH4 abatement technology, reporters must either use the manufacturer’s specified destruction efficiency or the destruction efficiency determined via a performance test; if the destruction efficiency is determined via a performance test, reporters must also report the name of the test method that was used during the performance test. Following the initial annual report containing this information, reporters will not be required to resubmit this information unless the information changes during a subsequent reporting year, in which case, the reporter must update the information in the submitted annual report. The final revisions to subpart BB also add a recordkeeping requirement at 40 CFR 98.287(d) for facilities to maintain a copy of the reported information. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. The EPA is also finalizing, as proposed, confidentiality determinations for the additional data elements to be reported as described in section VI. of this preamble. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Q. Subpart DD—Electrical Transmission and Distribution Equipment Use We are finalizing several amendments to subpart DD of part 98 (Electrical Transmission and Distribution Equipment Use) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.Q.1. of this preamble discusses the final revisions to subpart DD. The EPA received several comments on the proposed subpart DD revisions which are discussed in section III.Q.2. of this preamble. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the final revisions to subpart DD, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart DD This section summarizes the final amendments to subpart DD. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other final revisions to 40 CFR part 98, subpart DD can be found in this section and section III.Q.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. a. Revisions To Improve the Quality of Data Collected for Subpart DD The EPA is finalizing several revisions to subpart DD to improve the quality of the data collected under this subpart. First, we are generally finalizing the proposed revisions to the calculation, monitoring, and reporting requirements of subpart DD to require reporting of additional F–GHGs, except insulating gases with weighted average GWPs less than or equal to one will remain excluded from reporting under subpart DD. These final amendments will help to account for use and emissions of replacements for SF6, including fluorinated gas mixtures, with lower but still significant GWPs. We are revising 40 CFR 98.300(a) to redefine the source category to include equipment containing ‘‘fluorinated GHGs (F–GHGs), including but not limited to sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs).’’ These changes include: • Revising the threshold determination in 40 CFR 98.301 by adding new equations DD–1 and equation DD–2 (see section III.Q.1.b. of this preamble). • Revising the GHGs to report at 40 CFR 98.302 by adding a new equation DD–3, which is also used in the PO 00000 Frm 00045 Fmt 4701 Sfmt 4700 31845 definition of ‘‘reportable insulating gas,’’ discussed below. • Redesignating equation DD–1 as equation DD–4 at 40 CFR 98.303 and revising the equation to estimate emissions from all F–GHGs within the existing calculation methodology, including F–GHG mixtures. Equation DD–4 will maintain the facility-level mass balance approach of tracking and accounting for decreases, acquisitions, disbursements, and net increase in total nameplate capacity for the facility each year, but will apply the weight fraction of each F–GHG to determine the user emissions by gas. In the final rule, we are making two clarifications to equation DD–4 in addition to the revisions that were proposed. These are discussed further below. • Updating the monitoring and quality assurance requirements at 40 CFR 98.304(b) to account for emissions from additional F–GHGs. • To address references to F–GHGs and F–GHG mixtures, we are finalizing the term ‘‘insulating gas’’ which is defined as ‘‘any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc quenching gas in electrical equipment.’’ • To clarify which insulating gases are subject to reporting requirements, we are adding the term ‘‘reportable insulating gas,’’ which is defined as ‘‘an insulating gas whose GWP, as calculated in equation DD–3, is greater than one. A fluorinated GHG that makes up either part or all of a reportable insulating gas is considered to be a component of the reportable insulating gas.’’ In many though not all cases, we are replacing occurrences of the proposed phrase ‘‘fluorinated GHGs, including PFCs and SF6’’ with ‘‘fluorinated GHGs that are components of reportable insulating gases.’’ • Adding harmonizing requirements to the term ‘‘facility’’ in the definitions section at 40 CFR 98.308 and the requirements at 40 CFR 98.302, 98.305, and 98.306 to require reporters to account for the mass of each F–GHG for each electric power system. As noted above, following consideration of comments received, the EPA is revising these requirements from proposal to continue to exclude insulating gases with weighted average 100-year GWPs of less than one. Based on a review of the subpart DD data submitted to date, the EPA has concluded that excluding insulating gases with GWPs of less than one from reporting under subpart DD will have little effect on the accuracy or completeness of the GWP-weighted totals reported under subpart DD or E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31846 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations under the GHGRP generally at this time, and will decrease the reporting burden for facilities. See section III.Q.2. of this preamble for a summary of the related comments and the EPA’s response. Also as noted above, we are making two clarifications to equation DD–4 in addition to the revisions that were proposed. First, to account for the possibility that the same fluorinated GHG could be a component of multiple reportable insulating gases, we are inserting a summation sign at the beginning of the right side of equation DD–4 to ensure that emissions of each fluorinated GHG ‘‘i’’ are summed across all reportable insulating gases ‘‘j.’’ Second, upon further consideration of equation DD–4 and its relationship to the newly defined terms ‘‘new equipment’’ and ‘‘retiring equipment,’’ we are modifying the terms for acquisitions and disbursements of reportable insulating gas j to account for acquisitions and disbursements of reportable insulating gas that are linked to the acquisition or sale of all or part of an electric power system. These include acquisitions or disbursements of reportable insulating gas inside equipment that is transferred while in use, acquisitions or disbursements of insulating gas inside equipment that is transferred from or to entities other than electrical equipment manufacturers and distributors while the equipment is not in use, and acquisitions or disbursements of insulating gas in bulk from or to entities other than chemical producers or distributors. Accounting for these acquisitions and disbursements in equation DD–4 ensures that the terms for acquisitions and disbursements of reportable insulating gas will be mathematically consistent with other terms in the equation, including the terms for the net increase in total nameplate capacity and the quantity of gas stored in containers at the end of the year. The term for the net increase in the total nameplate capacity will reflect the new definitions of ‘‘new equipment’’ and ‘‘retiring equipment,’’ which include transfers of equipment while in use. Similarly, the term for the quantity of reportable insulating gas stored in containers at the end of the year will reflect acquisitions or disbursements of reportable insulating gas stored in containers from or to all other entities, including other electric power systems. If these acquisitions or disbursements of gas in equipment or in bulk are not accounted for in the equation, the result will be incorrect. The revised terms are consistent with the definitions of ‘‘new’’ and ‘‘retired’’ in their treatment of VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 hermetically sealed pressure equipment, with such equipment being included in terms related to equipment that is transferred while not in use, but excluded from terms related to equipment that is transferred while in use. We are also making harmonizing changes to the reporting requirements at 40 CFR 98.306, revising paragraphs (f), (g), and (i) (to be redesignated as paragraph (k)), and adding paragraphs (i), (n), and (o). These harmonizing revisions do not substantively change the reporting requirements as proposed and therefore would not substantively impact the burden to reporters. With minor changes, we are finalizing the proposed requirements in 40 CFR 98.303(b) for users of electrical equipment to follow certain procedures when they elect to measure the nameplate capacities (in units of mass of insulating gas) of new and retiring equipment rather than relying on the rated nameplate capacities provided by equipment manufacturers. As proposed, this option will be available only for closed pressure equipment with a voltage capacity greater than 38 kilovolts (kV), not for hermetically sealed pressure equipment or smaller closed-pressure equipment. These procedures are intended to ensure that the nameplate capacity values that equipment users measure match the full and proper charges of insulating gas in the electrical equipment. These procedures are similar to and compatible with the procedures for measuring nameplate capacity adopted by the California Air Resources Board (CARB) in its Regulation for Reducing Greenhouse Gas Emissions from Gas Insulated Switchgear.16 Specifically, electrical equipment users electing to measure the nameplate capacities of any new or retiring equipment will be required at 40 CFR 98.303(b)(1) to measure the nameplate capacities of all eligible new and retiring equipment in that year and in all subsequent years. For each piece of equipment, the electrical equipment user will be required to calculate the difference between the user-measured and rated nameplate capacities, verifying that the rated nameplate capacity was the most recent available from the equipment manufacturer. Where a user-measured nameplate capacity differs from the rated nameplate capacity by two percent or more, the electrical equipment user will be required at 40 CFR 98.303(b)(2) to adopt the user-measured nameplate capacity for that equipment for the 16 See https://ww2.arb.ca.gov/sites/default/files/ barcu/regact/2020/sf6/fro.pdf. PO 00000 Frm 00046 Fmt 4701 Sfmt 4700 remainder of the equipment’s life. Where a user-measured nameplate capacity differs from the rated nameplate capacity by less than two percent, the electrical equipment user will have the option at 40 CFR 98.303(b)(3) to adopt the user-measured nameplate capacity, but if they chose to do so, they must adopt the usermeasured nameplate capacities for all new and retiring equipment whose usermeasured nameplate capacity differed from the rated nameplate capacity by less than two percent. With minor changes, the EPA is finalizing the proposed requirements at 40 CFR 98.303(b)(4) and (5) for when electrical equipment users measure the nameplate capacity of new equipment that they install and for when they measure the nameplate capacity of retiring equipment. These final requirements ensure that electrical equipment users: • Correctly account for the mass of insulating gas contained in new equipment upon delivery from the manufacturer (i.e., the holding charge), and correctly account for the mass of insulating gas contained in equipment upon retirement, measuring the actual temperature-adjusted pressure and comparing that to the temperatureadjusted pressure that reflects the correct filling density of that equipment. • Use flowmeters or weigh scales that meet certain accuracy and precision requirements to measure the mass of insulating gas added to or recovered from the equipment; • Use pressure-temperature charts and pressure gauges and thermometers that meet certain accuracy and precision requirements to fill equipment to the density specified by the equipment manufacturer or to recover the insulating gas from the equipment to the correct blank-off pressure, allowing appropriate time for temperature equilibration; and • Ensure that insulating gas remaining in the equipment, hoses and gas carts is correctly accounted for. After consideration of comments, we are including a requirement to follow the procedure specified by the equipment manufacturer to ensure that the measured temperature accurately reflects the temperature of the insulating gas, e.g., by measuring the insulating gas pressure and vessel temperature after allowing appropriate time for the temperature of the transferred gas to equilibrate with the vessel temperature. Also after consideration of comments, we are (1) adding a requirement that facilities that use flow meters to measure the mass of insulating gas added to new equipment must keep the E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 mass flow rate within the range specified by the flowmeter manufacturer, and (2) not finalizing the option to use mass flowmeters to measure the mass of the insulating gas recovered from equipment. We are making both changes because the accuracy and precision of flowmeters can decrease significantly when the mass flow rate declines below the minimum specified by the flow meter manufacturer for accurate and precise measurements. As proposed, we are allowing equipment users to account for any leakage from the equipment using one of two approaches. In both approaches, users must measure the temperaturecompensated pressure of the equipment before they remove the insulating gas from that equipment and compare the measured temperature-compensated pressure to the temperaturecompensated pressure corresponding to the full and proper charge of the equipment (the design operating pressure). If the measured temperaturecompensated pressure is different from the temperature-compensated pressure corresponding to the full and proper charge of the equipment, the equipment user may either (1) add or remove insulating gas to or from the equipment until the equipment reaches its full and proper charge; recover the gas until the equipment reached a pressure of 0.068 pounds per square inch, absolute (psia) (3.5 Torr) or less; and weigh the recovered gas (charge adjustment approach), or (2) if (a) the starting pressure of the equipment is between its temperature-compensated design operating pressure and five (5) pounds per square inch (psi) below that pressure, and (b) the insulating gas is recovered to a pressure no higher than 5 psia (259 Torr),17 recover the gas that was already in the equipment; weigh it; and account mathematically for the difference between the quantity of gas recovered from the equipment and the full and proper charge (mathematical adjustment approach, equation DD–5). In the final rule, we are allowing use of the mathematical adjustment approach in somewhat more limited circumstances than proposed. We proposed that to use the mathematical adjustment approach to calculate the 17 While the mathematical adjustment approach is expected to yield accurate results if the final pressure is 5 psia or less, facilities are encouraged to recover the insulating gas until they reach the blank-off pressure of the gas cart, which is generally expected to fall below 5 psia. Note that where the final pressure is equal to or less than 0.068 psia, the gas remaining in the equipment is estimated to account for a negligible share of the total and therefore facilities are not required to use the Mathematical Adjustment Method to account for it. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 nameplate capacity, facilities would need to recover a quantity of insulating gas equivalent to at least 90 percent of the full manufacturer-rated nameplate capacity of the equipment, which would have provided more flexibility on the starting and ending pressures of the equipment during the recovery process. The proposed requirement was based on an analysis of the proposed accuracies and precisions of measuring devices and their impacts on the accuracy and precision of the mathematical adjustment approach, which indicated that 90 percent of the gas must be recovered to limit the uncertainty of the calculation to below 2 percent. We also recognized that departures from the ideal gas law could result in additional, systematic errors in the mathematical adjustment approach and therefore requested comment on the option of adding compressibility factors, which account for these departures, to equation DD–5 (proposed as equation DD–4). Such compressibility factors are not constant but are functions of the pressure and temperature of the insulating gas based on an equation of state specific to that insulating gas. We did not receive any comment on this option, and after considering the matter further, we believe that performing calculations using compressibility factors would prove too complex to implement in the field to obtain accurate nameplate capacity values. Without compressibility factors, departures of the insulating gas from the ideal gas law limit the reliability of the mathematical adjustment approach except within the ranges of starting and ending pressures described above. Consequently, we are finalizing the mathematical adjustment method as proposed but are restricting its use to the specified ranges of starting and ending pressures. Under these circumstances, any systematic errors in the mathematical adjustment approach are generally expected to fall below 0.5 percent, leading to maximum total errors (accounting for both departures from the ideal gas law and limits on the accuracy and precision of measuring devices) of approximately two percent. (For more discussion of this issue, see ‘‘Update to the Technical Support for Proposed Revisions to Subpart DD, Electrical Transmission and Distribution Equipment Use,’’ included in the docket for this rulemaking, Docket ID. No. EPA–HQ–OAR–2019–0424). Given these restrictions, the mathematical adjustment approach cannot be used to calculate the nameplate capacity of equipment that cannot have the insulating gas inside of PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 31847 it recovered below atmospheric pressure. However, as noted above, the approach can still be used for situations where the blank-off pressure of a gas cart is above 3.5 Torr (0.068 psia) but below 5 psia and/or where the starting pressure of the electrical equipment is no more than 5 psi lower than its temperature-compensated design operating pressure. (Note that equipment whose starting pressure is above the temperature-compensated design operating pressure will need to have the excess gas recovered until it reaches the design operating pressure, at which point the nameplate capacity measurement can begin.) We are finalizing as proposed requirements at 40 CFR 98.303(b)(6) that allow users to measure the nameplate capacity of electrical equipment earlier during maintenance activities that require opening the gas compartment. The equipment user will still be required to follow the measurement procedures required for retiring equipment at 40 CFR 98.303(b)(5) to measure the nameplate capacity, and the measured nameplate capacity must be recorded, but will not be used in equation DD–3 until that equipment is actually retired. We are finalizing as proposed requirements at 40 CFR 98.303(b)(7) and (8) to require that, where the electrical equipment user is adopting the usermeasured nameplate capacity, the user must affix a revised nameplate capacity label showing the revised nameplate value and the year the nameplate capacity adjustment process was performed to the device by the end of the calendar year in which the process was completed. For each piece of electrical equipment whose nameplate capacity is adjusted during the reporting year, the revised nameplate capacity value must be used in all rule provisions wherein the nameplate capacity is required to be recorded, reported, or used in a calculation. To ensure that the mass balance method is based on consistent nameplate capacity values throughout the life of the equipment, we are finalizing at 40 CFR 98.303(b)(9) that electrical equipment users are allowed to measure and revise the nameplate capacity value of any given piece of equipment only once, unless the nameplate capacity itself is likely to have changed due to changes to the equipment (e.g., replacement of the equipment bushings). To help ensure that electrical equipment users obtain accurate measurements of their equipment’s nameplate capacities, we are finalizing requirements at 40 CR 98.303(b)(10) that E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31848 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations electrical equipment users must use measurement devices that meet the following accuracy and precision requirements when they measure the nameplate capacities of new and retiring equipment: • Flow meters must be certified by the manufacturer to be accurate and precise to within one percent of the largest value that the flow meter can, according to the manufacturer’s specifications, accurately record. • Pressure gauges must be certified by the manufacturer to be accurate and precise to within 0.5 percent of the largest value that the gauge can, according to the manufacturer’s specifications, accurately record. • Temperature gauges must be certified by the manufacturer to be accurate and precise to within ±1.0 °F; and • Scales must be certified by the manufacturer to be accurate and precise to within one percent of the true weight. Additional information on these revisions and their supporting basis may be found in section III.N.1. of the preamble to the 2022 Data Quality Improvements Proposal. We are finalizing at 40 CFR 98.306(r) and (s) (proposed as 40 CFR 98.306(o) and (p)) requirements for equipment users who measure and adopt nameplate capacity values to report the total rated and measured nameplate capacities across all the equipment whose nameplate capacities were measured and for which the measured nameplate capacities have been adopted in that year. We are finalizing requirements in 40 CFR 98.307(b) as proposed for equipment users to keep records of certain identifying information for each piece of equipment for which they measure the nameplate capacity: the rated and measured nameplate capacities, the date of the nameplate capacity measurement, the measurements and calculations used to obtain the measured nameplate capacity (including the temperature-pressure curve and/or other information used to derive the initial and final temperature adjusted pressures of the equipment), and whether or not the measured nameplate capacity value was adopted for that piece of equipment. To clarify the mass balance methodology in 40 CFR 98.303, we are adding definitions for ‘‘energized,’’ ‘‘new equipment,’’ and ‘‘retired equipment,’’ at 40 CFR 98.308 as proposed. We are finalizing the definition of ‘‘energized’’ as proposed to mean ‘‘connected through busbars or cables to an electrical power system or fully-charged, ready for service, and VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 being prepared for connection to the electrical power system. Energized equipment does not include spare gas insulated equipment (including hermetically-sealed pressure switchgear) in storage that has been acquired by the facility, and is intended for use by the facility, but that is not being used or prepared for connection to the electrical power system.’’ The final definition more clearly designates what equipment is considered to be installed and functioning as opposed to being in storage. With two minor changes, we are finalizing the proposed definition for ‘‘new equipment.’’ ‘‘New equipment’’ is defined as ‘‘either (1) any gas insulated equipment, including hermeticallysealed pressure switchgear, that is not energized at the beginning of the reporting year but is energized at the end of the reporting year, or (2) any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been added to the facility’s inventory without being taken out of active service (e.g., when the equipment is sold to or acquired by the facility while remaining in place and continuing operation).’’ Similarly, we are finalizing the definition for ‘‘retired equipment’’ with two minor changes. ‘‘Retired Equipment’’ is defined as ‘‘either (1) any gas insulated equipment, including hermetically-sealed pressure switchgear, that is energized at the beginning of the reporting year but is not energized at the end of the reporting year, or (2) any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been removed from the facility’s inventory without being taken out of active service (e.g., when the equipment is acquired by a new facility while remaining in place and continuing operation).’’ The proposed definitions both included two sentences, where the first sentence specified that the equipment changed from ‘‘not energized’’ to ‘‘energized’’ (or vice versa), and the second sentence preceded the phrase ‘‘that has been transferred while in use’’ with ‘‘This includes.’’ Upon review of the proposed definitions, we realized that they could lead to confusion because equipment that is transferred while in use does not change from ‘‘not energized’’ to ‘‘energized’’ or vice versa, and therefore cannot be ‘‘included’’ in the sets of equipment that change from ‘‘not energized’’ to ‘‘energized’’ or vice versa. We therefore replaced ‘‘This includes’’ with ‘‘or.’’ We also realized that including hermetically-sealed pressure PO 00000 Frm 00048 Fmt 4701 Sfmt 4700 switchgear in equipment that is transferred while in use would trigger requirements to inventory the acquired (new) or disbursed (retired) hermetically-sealed pressure switchgear for purposes of the mass balance calculation (equation DD–4) and the reporting requirements at 40 CFR 98.306(a)(2) and (4). We did not intend to trigger these requirements for hermetically sealed pressure equipment that is transferred during use. Such requirements would be inconsistent with the intent and effect of the current provision at 40 CFR 98.306(a)(1), which excludes existing hermetically-sealed pressure switchgear from the requirement to report the existing nameplate capacity total at the beginning of the year. We therefore excepted hermetically sealed switchgear from equipment that is transferred while in use in both definitions. With these minor changes, the definitions clarify how the terms ‘‘new’’ and ‘‘retired’’ should be interpreted for purposes of equation DD–3. b. Revisions To Streamline and Improve Implementation for Subpart DD The EPA is finalizing several revisions to subpart DD to streamline requirements. First, we are revising the applicability threshold of subpart DD at 40 CFR 98.301 largely as proposed, in order to align with revisions to include additional F–GHGs in subpart DD. However, as discussed above, insulating gases with weighted average GWPs less than or equal to 1 will remain excluded from reporting under subpart DD. We are replacing the existing nameplate capacity threshold with an emissions threshold of 25,000 mtCO2e per year of F–GHGs that are components of reportable insulating gases (i.e., insulating gases whose weighted average GWPs, as calculated in equation DD–3, are greater than one (1)). To calculate their F–GHG emissions for comparison with the threshold, electrical equipment users will use one of two new equations finalized in subpart DD at 40 CFR 98.301, equations DD–1 and DD–2. The equations explicitly include not only the nameplate capacity of the equipment but also an updated default emission factor and the GWP of each insulating gas. We are also finalizing revisions to the existing calculation, monitoring, and reporting requirements of subpart DD to require reporting of additional F–GHGs beyond SF6 and PFCs that are components of reportable insulating gases. The new equations DD–1 and DD–2 that we are finalizing for the applicability threshold require potential E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations reporters to account for the total nameplate capacity of all equipment containing reportable insulating gases (located on-site and/or under common ownership or control), including equipment containing F–GHG mixtures, and multiply by the weight fraction of each F–GHG (for gas mixtures), the GWP for each F–GHG, and an emission factor of 0.10 (representing an emission rate of 10 percent). We are finalizing harmonizing changes in multiple sections of subpart DD to renumber equation DD–1 and maintain cross-references to the equation. We are also finalizing revisions to the existing threshold in 40 CFR 98.301 and table A–3 to subpart A (General Provisions). Additional information on these revisions and their supporting basis may be found in section III.N.2. of the preamble to the 2022 Data Quality Improvements Proposal. Finally, we are removing an outdated monitoring provision at 40 CFR 98.304(a), which reserves a prior requirement for use of BAMM that applied solely for RY2011. lotter on DSK11XQN23PROD with RULES2 2. Summary of Comments and Responses on Subpart DD This section summarizes the major comments and responses related to the proposed amendments to subpart DD. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart DD. a. Comments on Revisions To Improve the Quality of Data Collected for Subpart DD Comment: One commenter asked for clarification regarding whether the equipment user needs to account for insulating gas remaining inside gasinsulated equipment (GIE) that are transferred to another entity (vendor) for repair or salvage. The commenter asserted that since the equipment is leaving the inventory with gas inside, it should be counted as both retired equipment and a gas disbursement. The commenter suggested the ‘‘Disbursements’’ term in equation DD– 3 be modified to include similar language to the ‘‘Acquisitions’’ term, to clarify that gas inside equipment that is transferred to another entity for repair or salvage, in addition to equipment that is sold, counts as a disbursement. Response: The EPA agrees with the commenter and is revising the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 ‘‘Disbursements’’ term in equation DD– 3 (being finalized as equation DD–4) to account for gas ‘‘transferred’’ as well as ‘‘sold’’ to ‘‘other entities.’’ As discussed in section III.Q.1. of this preamble, we are making a number of clarifications to the ‘‘Acquisitions’’ and ‘‘Disbursements’’ terms in equation DD– 4 to accommodate the full range of possible acquisitions and disbursements by electric power systems, which will improve the accuracy and completeness of equation DD–4 and the associated reporting and recordkeeping requirements. Comment: One commenter suggested that the EPA revise the nameplate capacity adjustment text as follows: first, to remove the word ‘‘covered’’ prior to ‘‘insulating gas’’ in 40 CFR 98.303(b)(4)(ii)(A), since ‘‘covered’’ is not included in the EPA’s definition of insulating gas. Response: The EPA agrees with the commenter and is revising 40 CFR 98.303(b)(4)(ii)(A) as suggested to reflect the language which is used in the definitions and to minimize confusion. As discussed in section III.Q.1. of this preamble, we are introducing the term ‘‘reportable insulating gas’’ to distinguish between insulating gas that is included in subpart DD (‘‘reportable’’) because it has a weighted average GWP greater than 1 and insulating gas that is not reportable because it has a weighted average GWP of 1 or less. Comment: Two commenters suggested the EPA change the language in 40 CFR 98.303(b)(5)(ii), which was proposed as a requirement to ‘‘convert the initial system pressure to a temperaturecompensated initial system pressure by using the temperature/pressure curve for that insulating gas.’’ The commenters stated that the temperature/ pressure curve is not intended for conversions of initial system pressure to temperature-compensated pressure. The commenters suggested that the requirement should be to compare the measured initial system pressure and vessel temperature to the equipment manufacturer’s temperature-pressure curve specific for the equipment to confirm the equipment is at the proper operating pressure, prior to recovery of the insulating gas. One commenter recommended two options for measuring initial gas pressure: (1) use external pressure and temperature gauges according to 40 CFR 98.303(b)(5)(i); or (2) if an integrated temperature-compensated gas pressure gauge was used for the initial gas fill and to monitor and maintain the gas at the proper operating pressure over the service life of the circuit breaker, use the same gauge to determine whether the PO 00000 Frm 00049 Fmt 4701 Sfmt 4700 31849 circuit breaker is at the proper operating pressure. Response: The EPA agrees with the commenters regarding the language at 40 CFR 98.303(b)(5)(ii) and is finalizing the requirement as follows: ‘‘Compare the initial system pressure and temperature to the equipment manufacturer’s temperature/pressure curve for that equipment and insulating gas.’’ Regarding allowing use of an integrated temperature-compensated gas pressure gauge, use of such a gauge is allowed if the gauge is certified by the gauge manufacturer to be accurate and precise to within 0.5 percent of the largest value that the gauge can, according to the manufacturer’s specifications, accurately record. It is EPA’s understanding that many gauges that are built into the electrical equipment do not meet these accuracy and precision requirements. However, if they do, the rule does not prohibit their use in nameplate capacity measurements. Comment: One commenter objected to the proposed requirement to recover the insulating gas to a blank-off pressure not greater than 3.5 Torr during the nameplate capacity measurement. The commenter noted that not all facilities own gas carts capable of reaching 3.5 Torr, and, for some GIE, that level of pressure is not necessary for an accurate reading. The commenter recommended that the GIE recovery be performed to allow for 99.1 percent or greater recovery of the insulating gas. Response: As discussed above, the EPA is finalizing a requirement that facilities measuring the nameplate capacity of their equipment recover the gas to a pressure of at most 5 psia (258.6 Torr). This will accommodate gas carts that are not capable of reaching 3.5 Torr. To ensure that the gas remaining in the equipment at pressures above 3.5 Torr is accounted for, facilities that recover the gas to a pressure between 5 psia and 3.5 Torr will be required to use the mathematical adjustment approach (equation DD–5) to calculate the full nameplate capacity. As discussed in the preamble to the proposed rule, the EPA estimates that 0.1 percent of the full and proper charge of insulating gas would remain in the equipment at 3.5 Torr (assuming that a full and proper charge has a pressure of 3800 Torr), a negligible fraction. However, the fraction of gas remaining after recovery of 99.1 percent of the gas, 0.9%, is not negligible, but represents a significant systematic underestimate compared to the 2% tolerance for nameplate capacity measurements. Since it is straightforward to correct for this systematic underestimate by using the E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31850 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations mathematical adjustment approach, we are requiring use of equation DD–5 in such situations. Comment: One commenter representing manufacturers of electrical equipment recommended that after insulating gas was added to a piece of electrical equipment, facilities should allow at least 24 hours to allow the gas to condition itself to its container in order to confirm the correct density has been met. Response: The EPA is adding a requirement to 40 CFR 98.303(b)(4)(ii) that facilities follow the procedure specified by the electrical equipment manufacturer to ensure that the measured temperature accurately reflects the temperature of the insulating gas, e.g., by measuring the insulating gas pressure and vessel temperature after allowing appropriate time for the temperature of the transferred gas to equilibrate with the vessel temperature. This allows for the possibility that some electrical equipment, e.g., electrical equipment with smaller charge sizes, may require less than 24 hours for the insulating gas temperature to equilibrate with the temperature of the vessel. Because achieving the correct density of the insulating gas in the equipment is important to the proper functioning of the equipment, the guidance provided by the equipment manufacturer should be sufficient to ensure that the appropriate density is achieved for purposes of the nameplate capacity measurement. Comment: Commenters representing electrical equipment users and manufacturers provided input on the use of mass flow meters to measure the nameplate capacities of new and retiring electrical equipment. One commenter provided recommended edits to the proposed text to add requirements to ensure that a minimum gas flow is maintained while measuring the mass of insulating gas being added to new equipment. The commenter stated that to ensure that the flowmeter was properly configured for its application, the maximum and minimum flow rates of the meter, as well as the displacement of the pumps and compressors on the gas cart being used, must be taken into consideration. The commenter added that, in general, mass flow meters designed for high flow applications will not be suitable for low flow conditions and meters designed for low flow applications will not be suitable for high flow conditions. This commenter also recommended adding the use of an incalibration cylinder scale as an alternative option for measuring the gas transferred during the equipment filling process. Two commenters VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 recommended removing the option to use a mass flow meter to measure the mass of insulating gas recovered from retiring equipment due to the potential for errors when a mass flow meter is used in this process. The commenters stated that use of a mass flow meter to measure the insulating gas recovered is not recommended since a mass flow meter does not accurately measure gas at low flow rates. Instead, the commenters recommended that the gas container weighing method should be used to accurately measure the total weight of insulating gas recovered from the equipment. One commenter added that the process of weighing all gas removed from a GIE and transferred into a cylinder includes weighing all the gas trapped in hoses and in gas cart, which would not be accounted for by the flow meter; the commenter pointed out that the gas (trapped in hoses and in the gas cart) would need to be moved into cylinders to be accurately weighed with a cylinder scale. Response: After consideration of these comments, the EPA is finalizing the proposed provisions for measuring the nameplate capacities of new and retiring equipment with two changes. First, we are requiring that facilities that use mass flow meters to measure the mass of insulating gas added to new equipment must keep the mass flow rate within the range specified by the mass flow meter manufacturer to assure an accurate and precise mass flow meter reading. Second, we are removing the option to use mass flow meters to measure the quantity of gas recovered from retiring equipment. We have analyzed the impact of the uncertainty of flowmeters at low flow rates on overall nameplate capacity measurements, and we have concluded that this impact may lead to large errors under some circumstances. As noted by the commenters, the relative error for flowmeters can increase when the flowmeter is used to measure mass flow rates below a certain fraction of the maximum full-scale value, and the mass flow rate will gradually decline as the insulating gas is transferred from the container to the equipment or vice versa, reducing the density of the gas inside the source vessel. For measuring the quantity of insulating gas added to new equipment, this issue can be addressed by requiring that the mass flow rate be kept within the range specified by the mass flow meter manufacturer, which can be accomplished by, e.g., switching to a full container when the density of the insulating gas in the current container falls below the minimum level. However, for measuring the quantity of PO 00000 Frm 00050 Fmt 4701 Sfmt 4700 insulating gas recovered from retiring equipment, the insulating gas is being transferred from the equipment itself, and the recovery process therefore inevitably lowers the mass flow rate below the minimum level. For this reason, we are not taking final action on the option to use flowmeters to measure the quantity of insulating gas recovered from retiring equipment. In our analysis of this issue, we reviewed our proposal at 40 CFR 98.303(b)(10) that mass flow meters must be accurate and precise to within one percent of the largest value that the flow meter can, according to the manufacturer’s specifications, accurately record, i.e., the maximum full-scale value. This means that the relative error of the flowmeter could rise hyperbolically from one percent of the measured value (when the measured value equals the maximum value) to much higher levels at lower flow rates, e.g., 2 percent of the flow rate at half the maximum, 4 percent of the flow rate at one quarter of the maximum, 10 percent of the flow rate at one tenth the maximum, etc. These rising relative errors lead to overall errors in the mass flow measurement that are far above one percent. Even if the flow meter is accurate to within one percent of the measured value over a ten-fold range of flow rates, errors at lower flow rates can be significant. In an example provided to us by a company that provides insulating gas recovery equipment (gas carts) and insulating gas recovery services to electric power systems, the relative error of the measurement of the flow rate rose by a factor of five when the flow rate fell below 10 percent of the maximum full-scale value. If the error of a flowmeter climbed from 1 percent to 5 percent when the flow rate fell below 10 percent of the maximum full-scale value, the measurement of the total mass recovered would have a maximum uncertainty of 1.4 percent, which can result in overall errors above 2 percent in the nameplate capacity measurement as a whole (accounting also for the uncertainties of measured pressures, etc.). Regarding one commenter’s recommendation that we allow weigh scales to be used to measure the quantity of gas filled into new equipment, we are finalizing our proposal at 40 CFR 98.303(b)(4)(ii)(A) to allow use of weigh scales for this measurement. Comment: Two commenters requested the EPA remove the term ‘‘precise’’ from proposed 40 CFR 98.303(b)(10). Both commenters stressed that accuracy is more important. One commenter stated that equipment certified to be accurate E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations and precise may be difficult to find, and another additionally asserted there is little value in precision. Response: In the final rule, we are finalizing as proposed the accuracy and precision requirements for gauges, flow meters, and weigh scales used to measure nameplate capacities. To obtain an accurate measurement of the nameplate capacity of a piece of equipment, measurement devices must be both accurate and precise. As discussed in the technical support document for the proposed rule,18 the term ‘‘accurate’’ indicates that multiple measurements will yield an average that is near the true value, while the term ‘‘precise’’ indicates that multiple measurements will yield consistent results. A measurement device that is accurate without being precise may show inconsistent results from measurement to measurement, and these individual inconsistent results may be significantly different from the true value even if their average is not. Since measurements of nameplate capacity are generally expected to be taken only once for a particular piece of equipment, the devices on which the individual measurements are taken must be both accurate and precise for the measurements to yield results that are near the true values. Comment: One commenter suggested redefining the definition of ‘‘insulating gas’’ to including any gas with a GWP greater than one (1) and not any fluorinated GHG or fluorinated GHG mixture. The commenter urged that the proposed definition ignores other potential gases that may come onto the market that are not fluorinated but still have a GWP. The commenter stated that defining insulating gas to include any gas with a GWP greater than 1 used as an insulating gas and/or arc quenching gas in electrical equipment would mirror the threshold implemented by the California Air Resources Board and would provide consistency for reporters across Federal and State reporting rules. Response: In the final rule, the EPA is not requiring electric power systems to track or report emissions of insulating gases with weighted average 100-year GWPs of one or less. Based on a review of the subpart DD data submitted to date, the EPA has concluded that excluding insulating gases with weighted average GWPs of one or less from reporting under subpart DD will have little effect on the accuracy or completeness of the GWP-weighted 18 See ‘‘Technical Support for Proposed Revisions to Subpart DD (2021),’’ available in the docket to this rulemaking, Docket ID. No. EPA–HQ–OAR– 2019–0424. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 totals reported under subpart DD or under the GHGRP generally. Between 2011 and 2021, the highest emitting facilities reporting under subpart DD reported SF6 emissions ranging from 8 to 23 mt (unweighted) or 190,000 to 540,000 mtCO2e. Over the same period, total emissions across all facilities have ranged from 96 to 171 mt (unweighted) or 2.3 to 4.1 million mtCO2e. At GWPs of one, these weighted totals would be equivalent to the unweighted quantities reported, which constitute approximately 0.004% (1/23,500) of the GWP-weighted totals. This does not account for the fact that for the first few years it is sold, equipment containing insulating gases with weighted average GWPs of one or less will make up a small fraction of the total nameplate capacity of the electrical equipment in use. (Electrical equipment has a lifetime of about 40 years, so only a small fraction of the total stock of equipment is retired and replaced each year.) Even in a worst-case scenario where the annual emission rate of the equipment containing a very low-GWP insulating gas was assumed to equal the total nameplate capacity of all the equipment installed (implying an emission rate of 100 percent, higher than any ever reported under the GHGRP), the total GWP-weighted emissions reported under subpart DD would be considerably smaller than those reported under any other subpart: total unweighted nameplate capacities reported across all facilities to date have ranged between 4,847 and 6,996 mt. At GWPs of 1, these totals would fall under the 15,000 and 25,000 mtCO2e quantities below which individual facilities are eventually allowed to exit the program under the off-ramp provisions, as applicable. To monitor trends in the replacement of SF6 by insulating gases with weighted average GWPs less than one, the EPA will continue to track supplies of such insulating gases under subparts OO and QQ and will track deliveries of such insulating gases in equipment or containers under subpart SS. b. Comments on Revisions To Streamline and Improve Implementation for Subpart DD Comment: One commenter supported the proposed threshold for subpart DD but wanted the EPA to clarify that reporters that do not think they will fall below the revised reporting threshold or are not otherwise using F–GHGs other than SF6 do not need to recalculate their emissions to show they must report. Response: The applicability threshold is for determining whether entities must initially begin reporting to the GHGRP. PO 00000 Frm 00051 Fmt 4701 Sfmt 4700 31851 Facilities that have reported have calculated their emissions more precisely using the mass balance approach. If those calculations have shown that they are eligible to exit the program under the off-ramp provisions of subpart A of part 98 (40 CFR 98.2(i)), they do not need to report again unless facility emissions exceed 25,000 mtCO2e. On the other hand, if the calculations have shown that the facility does not meet the existing off-ramp conditions to exit the program, they must continue reporting regardless of the results of the threshold calculation at 40 CFR 98.301. R. Subpart FF—Underground Coal Mines We are finalizing the amendments to subpart FF of part 98 (Underground Coal Mines) as proposed. The EPA received no comments objecting to the proposed revisions to subpart FF; therefore, there are no changes from the proposal to the final rule. The EPA is finalizing two technical corrections to: (1) correct the term ‘‘MCFi’’ in equation FF–3 to subpart FF to revise the term ‘‘1-(fH2O)1’’ to ‘‘1-(fH2O)i’’, and (2) to correct 40 CFR 98.326(t) to add the word ‘‘number’’ after the word ‘‘identification’’ to clarify the reporting requirement. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. S. Subpart GG—Zinc Production This section discusses the final revisions to subpart GG. We are finalizing amendments to subpart GG of part 98 (Zinc Production) as proposed. The EPA received only supportive comments for the proposed revisions to subpart GG. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA– HQ–OAR–2019–0424 for a complete listing of all comments and responses related to subpart GG. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. The EPA is finalizing one revision to add a reporting requirement at 40 CFR 98.336(a)(6) and (b)(6) for the total amount of electric arc furnace (EAF) dust annually consumed by all Waelz kilns at zinc production facilities. The final data elements will only require segregation and reporting of the mass of EAF dust consumed for all kilns. These requirements apply to reporters using either the CEMS direct measurement or mass balance calculation E:\FR\FM\25APR2.SGM 25APR2 31852 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations methodologies. Reporters currently collect information on the EAF dust consumed on a monthly basis as part of their existing operations as a portion of the inputs to equation GG–1 to subpart GG; reporters will only be required to sum all EAF dust consumed on a monthly basis for each kiln and then for all kilns at the facility for reporting and entering the information into e-GGRT. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the final revisions to subpart GG, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart HH This section summarizes the final amendments to subpart HH. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart HH can be found in this section and section III.T.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. The EPA is finalizing several revisions to subpart HH to improve the quality of data collected under the GHGRP. First, the EPA is finalizing revisions to update the factors used in modeling CH4 generation from waste disposed at landfills in table HH–1 to subpart HH. As explained in the 2022 Data Quality Improvements Proposal, subpart HH uses a model to estimate CH4 generation that considers the quantity of MSW landfilled, the degradable organic carbon (DOC) content of that MSW, and the first order decay rate (k) of the DOC. Table HH–1 to subpart HH provides DOC and k values that a reporter must use to calculate their CH4 generation based on the different categories of waste disposed at that landfill and the climate in which the landfill is located. The EPA previously conducted a multivariate analysis of data reported under subpart HH to estimate updated DOC and k values for each waste characterization option. Details of this analysis are available in the memorandum from Meaghan McGrath, Kate Bronstein, and Jeff Coburn, RTI T. Subpart HH—Municipal Solid Waste Landfills We are finalizing several amendments to subpart HH of part 98 (Municipal Solid Waste Landfills) as proposed. In some cases, we are finalizing the proposed amendments with revisions. In other cases, we are not taking final action on the proposed amendments. Section III.T.1. of this preamble discusses the final revisions to subpart HH. The EPA received several comments on proposed subpart HH revisions which are discussed in section III.T.2. of this preamble. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the final revisions to subpart HH, as described in section VI. of this preamble. International, to Rachel Schmeltz, EPA, ‘‘Multivariate analysis of data reported to the EPA’s Greenhouse Gas Reporting Program (GHGRP), Subpart HH (Municipal Solid Waste Landfills) to optimize DOC and k values,’’ (June 11, 2019), available in the docket for this rulemaking, Docket ID. No. EPA–HQ– OAR–2019–0424. The EPA is finalizing the following changes as proposed: • For the Bulk Waste option, amending the bulk waste DOC value in table HH–1 from 0.20 to 0.17. • For the Modified Bulk Waste option, for bulk MSW waste without inerts and (C&D) waste, amending the DOC value from 0.31 to 0.27. • For the Waste Composition option, adding a DOC for uncharacterized MSW of 0.32, and revising 40 CFR 98.343(a)(2) to reference using this uncharacterized MSW DOC value rather than the bulk MSW value for waste materials that could not be specifically assigned to the streams listed in table HH–1 for the Waste Composition option. The EPA is also revising the default decay rate values in table HH–1 for the Bulk Waste option and the Modified Bulk MSW option and adding k value ranges for uncharacterized MSW for the Waste Composition Option. The final k values, which have been revised from those proposed, are shown in table 4 of this preamble. The revised defaults represent the average optimal k values derived through an additional optimization analysis conducted in response to comments where the bulk waste DOC value was set to the revised value of 0.17 and optimal k values were determined for each precipitation category. TABLE 4—REVISED DEFAULT k VALUES Factor lotter on DSK11XQN23PROD with RULES2 k k k k k k Subpart HH default values for Bulk Waste option and Modified Bulk MSW option .......................................................... (precipitation plus recirculated leachate <20 inches/year) ................................................................ (precipitation plus recirculated leachate 20–40 inches/year) ............................................................ (precipitation plus recirculated leachate >40 inches/year) ................................................................ value range for Waste Composition option ....................................................................................... (uncharacterized MSW) ..................................................................................................................... The revisions to the DOC and k values in table HH–1 reflect the compositional changes in materials that are disposed at landfills. These updated factors will allow MSW landfills to more accurately model their CH4 generation. We are also clarifying in the final rule that starting in RY2025 these new DOC and k values are to be applied for disposal years 2010 and later, consistent with when the compositional changes occurred. Additional information on these VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 revisions and their supporting basis may be found in section III.Q. of the preamble to the 2022 Data Quality Improvements Proposal and in the memorandum ‘‘Revised Analysis and Calculation of Optimal k Values for Subpart HH MSW Landfills Using a 0.17 DOC Default and Timing Considerations’’ included in Docket ID. No. EPA–HQ–OAR–2019–0424. We are also finalizing, as proposed, revisions to account for CH4 emission PO 00000 Frm 00052 Fmt 4701 Sfmt 4700 Units 0.033 ........................................... 0.067 ........................................... 0.098 ........................................... yr¥1. yr¥1. yr¥1. 0.033 to 0.098 ............................ yr¥1. events that are not well quantified under the GHGRP including: (1) a poorly operating or non-operating gas collection system; and (2) a poorly operating or non-operating destruction device. The EPA is finalizing, as proposed, revisions and additions to address these scenarios as follows: • Revising equations HH–7 and HH– 8 to more clearly indicate that the ‘‘fRec’’ term is dependent on the gas collection system, to clarify how the equation E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations applies to landfills that may have more than one gas collection system and may have multiple measurement locations associated with a single gas collection system. • Clarifying in ‘‘fRec’’ that the recovery system operating hours only include those hours when the system is operating normally. Facilities should not include hours when the system is shut down or when the system is poorly operating (i.e., not operating as intended). Poorly operating systems can be identified when pressure, temperature, or other parameters indicative of system performance are outside of normal variances for a significant portion of the system’s gas collection wells. • For equations HH–6, HH–7, and HH–8, revising the term ‘‘fDest’’ to clarify that the destruction device operating hours exclude periods when the destruction device is poorly operating. Facilities should only include those periods when flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter that is indicative of effective operation. For flares, periods when there is no flame present must be excluded from the annual operating hours. Following consideration of comments received, the EPA is finalizing two minor clarifications of the term ‘‘fDest,n’’ in equations HH–7 and HH–8. First, we are removing the redundant phrase ‘‘as measured at the nth measurement location.’’ Second, we are removing the word ‘‘pilot’’ to clarify that for flares used as a destruction device, the annual operating hours must exclude any period in which no flame is present, either pilot or main. These changes account for variances in flare operation, e.g., flares which may only use a pilot on startup. See section III.T.2. of this preamble for additional information on related comments and the EPA’s response. In the 2023 Supplemental Proposal, we proposed that facilities that conduct surface-emissions monitoring must use that data and correct the emissions calculated in equations HH–6, HH–7, and HH–8 to account for excess emissions when the measured surface methane concentration exceeded 500 ppm based on a correction term added to those equations. We also proposed for facilities not conducting surfaceemissions monitoring to use collection efficiencies that are 10-percentage points lower than the historic collection efficiencies in table HH–3 to subpart HH. Following consideration of comments received, we are not taking final action on the surface-emissions VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 monitoring correction term that was proposed. Instead, we are finalizing the proposed lower collection efficiencies in table HH–3 to subpart HH, but applying the reduced collection efficiencies for all reporters under subpart HH. See section III.T.2. of this preamble for additional information on related comments and the EPA’s response. The EPA is also finalizing several revisions to the reporting requirements for subpart HH, including more clearly identifying reporting elements associated with each gas collection system, each measurement location within a gas collection system, and each control device associated with a measurement location. First, we are finalizing revisions to landfills with gas collection systems consistent with the proposed revisions in the methodology, i.e., to separately require reporting for each gas collection systems and for each measurement location within a gas collection system. We are requiring, for each measurement location that measures gas to an on-site destruction device, certain information be reported about the destruction device, including: type of destruction device; the total annual hours where gas was sent to the destruction device; a parameter indicative of effective operation, such as the annual operating hours where active gas flow was sent to the destruction device and the destruction device was operating at its intended temperature; and the fraction of the recovered methane reported for the measurement location directed to the destruction device. We are also requiring reporting of identifying information for each gas collection system, each measurement location within a gas collection system, and each destruction device. We are also finalizing reporting requirements for landfills with gas collection systems to indicate the applicability of the NSPS (40 CFR part 60, subparts WWW or XXX), state plans implementing the EG (40 CFR part 60, subparts Cc or Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO). In the 2023 Supplemental Proposal, the EPA also sought comment on how other CH4 monitoring technologies, e.g., satellite imaging, aerial measurement, vehicle-mounted mobile measurement, or continuous sensor networks, might enhance subpart HH emissions estimates. The EPA did not propose, and therefore is not taking final action on, any amendments to subpart HH to this effect. However, the EPA did seek comment on the availability of existing monitoring technologies, and regulatory approaches and provisions necessary to incorporate such data into subpart HH PO 00000 Frm 00053 Fmt 4701 Sfmt 4700 31853 for estimating annual emissions. We will continue to review the comments received along with other studies and may amend subpart HH to allow the incorporation of additional measurement or monitoring methodologies in the future. 2. Summary of Comments and Responses on Subpart HH This section summarizes the major comments and responses related to the proposed amendments to subpart HH. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart HH. Comment: Numerous commentors stated that methane detection technology, specifically top-down direct measurement from aerial studies, has greatly improved the ability to observe and quantify emissions from landfills (e.g., Krautwurst, et al., 2017; Cusworth, et al., 2022).19 20 Some commenters noted that, among several studies in California, Maryland, Texas, and Indiana, there are discrepancies between observed data collected from these new detection technologies and the estimated emissions from the models that the EPA currently uses. Several commenters pointed to a recent study (Nesser, et al., 2023) using satellite data that highlighted that at 33 of 70 landfills studied, U.S. GHG Inventory landfill emissions are underestimated by 50 percent when compared to the current top-down approaches.21 These discrepancies indicate methane emissions from landfills may be considerably higher than currently recorded. Some commenters stated that advanced methane monitoring technology has improved significantly in effectiveness and cost, and provided specific input regarding advanced methane monitoring technologies available for landfills and how their data might enhance subpart 19 Krautwurst, S., et al., (2017). ‘‘Methane emissions from a Californian landfill, determined from airborne remote sensing and in situ measurements.’’ Atmos. Meas. Tech. 10:3429–3452. https://doi.org/10.5194/amt-10-3429-2017. 20 Cusworth, D., et al., (2020). ‘‘Using remote sensing to detect, validate, and quantify methane emissions from California solid waste operations.’’ Environ. Res. Lett. 15: 054012. 21 Nesser, H., et al. 2023. High-resolution U.S. methane emissions inferred from an inversion of 2019 TROPOMI satellite data: contributions from individual states, urban areas, and landfills, EGUsphere [preprint], https://doi.org/10.5194/ egusphere-2023-946, 2023. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31854 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations HH emissions reporting. The commenters pointed to both screening and close-range technologies that would be beneficial for pinpointing leaks or emission sources, and outlined several technologies including satellite imaging, aerial measurements, vehicle-mounted mobile measurement, and continuous sensor networks. The commenters recommended comprehensive monitoring with both screening and close-range technologies to provide full coverage. The commenters suggested the use of these technologies to catch large emission events that are not accounted for in the existing reporting requirements. Commenters noted that the EPA could review submitted reports and activity data to determine how to best quantify the observed large release events as compared to annual reported emissions (e.g., updating fRec or fDest values to account for periods of downtime or poor performance not captured that contributed to a large discrepancy). Other commenters recommended that the EPA create a mechanism under subpart HH for receiving and considering third-party observational data that the EPA could then use to revise reported emissions as necessary. Some commenters suggested the EPA base a threshold for these sources of 100 kg/hour. Commenters also recommended setting assumptions for the duration of the emissions similar to those proposed for subpart W of part 98 (Petroleum and Natural Gas Systems). Some commenters suggested the EPA should embrace for landfills the same tiered methane emissions monitoring approach as is utilized in its proposed rulemaking for the oil and gas sector. Commenters also suggested a tiered approach that combines continuous monitoring ground systems with periodic remote sensing along with approaches for translating methane concentrations from top-down sources to source-specific emission rates. Commenters urged that the sooner the EPA can move toward top-down or facility-wide measurement of emissions for reporting or validation of reported values, the sooner reported and measured emissions would be reconcilable and verifiable. A few commenters also recommended that the EPA facilitate the flow of information from other agencies (the National Aeronautics and Space Administration (NASA), National Oceanic and Atmospheric Administration (NOAA), National Institute of Standards and Technology (NIST), and U.S. Department of Energy (DOE)), third VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 parties, and operators to find and mitigate plumes faster. Several commenters provided recommendations for additional reporting requirements such as gas collection and capture system (GCCS) type and design, destruction device type and characteristics, monitoring technologies, site cover type, construction periods, and compliance issues which may relate to closures of control devices. Response: The EPA agrees that recent aerial studies indicate methane emissions from landfills may be considerably higher than bottom-up emissions reported under subpart HH for some landfills. Emissions may be considerably higher due to emissions from poorly operating gas collection systems or destruction devices and leaking cover systems. The supplemental proposal included revisions to the monitoring and calculation methodologies in subpart HH to account for these scenarios. In particular, proposed equations HH–6, HH–7, and HH–8 included modifications to incorporate direct measurement data collected from methane surface-emissions monitoring. In the supplemental proposal, we also requested information about other direct measurement technologies and how their data may enhance emissions reporting under subpart HH. We received many responses to our request. Based on the comments received, we are not taking final action at this time regarding the incorporation of other direct measurement technologies for the following reasons. First, most top-down, facility measurements are taken over limited durations (a few minutes to a few hours) typically during the daylight hours and limited to times when specific meteorological conditions exist (e.g., no cloud cover for satellites; specific atmospheric stability and wind speed ranges for aerial measurements). These direct measurement data taken at a single moment in time may not be representative of the annual CH4 emissions from the facility, given that many emissions are episodic. If emissions are found during a limited duration sampling, that does not necessarily mean they are present for the entire year. And if emissions are not found during a limited duration sampling, that does not mean significant emissions are not occurring at other times. Extrapolating from limited measurements to an entire year therefore creates risk of either over or under counting actual emissions. Second, while top-down measurement methods, including satellite and aerial methods, have proven their ability to PO 00000 Frm 00054 Fmt 4701 Sfmt 4700 identify and measure large emissions events, their detection limits may be too high to detect emissions from sources with relatively low emission rates or that are spread across large areas, which is common for landfills.22 This is likely why only seven percent of the landfills in the Duren, et al. (2019) study had detectable emissions. The EPA will continue to review additional information on existing and advanced methodologies and new literature studies, and consider ways to effectively incorporate these methods and data in future revisions under subpart HH for estimating annual emissions. For the oil and gas sector, the superemitter program that allows third-party measurement data to be submitted was proposed under 40 CFR part 60, subpart OOOOb (87 FR 74702, December 6, 2022). The GHGRP looked to use this information, but we did not develop or propose such a program under the GHGRP. As such, this type of program is beyond the scope of the proposed rule. We will consider whether developing and implementing a similar super-emitter program within subpart HH of part 98 or the overall GHGRP is appropriate under future rulemakings. We proposed, and are finalizing, several additional reporting elements including, for landfills with a gas collection system, information on the applicability of the NSPS (40 CFR part 60, subparts WWW or XXX), state plans implementing the EG (40 CFR part 60, subparts Cc or Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO). We note that several of the items suggested are already reporting elements. For example, we already require reporting of a description of the gas collection system, such as the manufacturer, capacity, and number of wells, which provides requested information on GCCS type and design. We also proposed and are finalizing reporting requirements for the type of destruction device. We already require reporting of cover type. We consider the reporting requirements to be sufficient based on the current methodologies used to estimate CH4 emissions. We will consider the need for additional reporting elements if we incorporate additional measurement or monitoring methodologies in future rulemakings. Comment: Several commentors expressed limited support for the proposed use of surface emission monitoring data to help account for 22 Duren, et al. 2019. ‘‘California’s methane superemitters.’’ Nature, Vol. 575, Issue 7781, pp. 180– 184, available at https://doi.org/10.1038/s41586019-1720-3. Available in the docket for this rulemaking, Docket ID. No. EPA–HQ–OAR–2023– 0234. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 emissions from cover leaks. These commenters either recommended that the EPA use more quantitative emission measurement methods instead of surface-emissions monitoring or to require that the surface-emissions monitoring be conducted at 25-foot intervals consistent with California and other state requirements, and to use a lower leaks definition of 25 parts per million volume (ppmv), rather than using the proposed 30-meter intervals (about 98-foot intervals) with leaks defined as concentrations of 500 ppmv or more above background, to help ensure the surface-emissions monitoring identifies all leaks from the landfill’s surface. Other commenters opposed the proposed use of a surface-emissions monitoring correction term in equations HH–6, HH–7, and HH–8. One commenter noted that the correction term that the EPA proposed relied on one study conducted over 20 years ago at one landfill in Canada. This commenter cited several other studies 23 24 25 26 that showed significant variability in correlations between surface methane concentrations and methane emissions and indicated that the EPA should not rely on the results of this limited single study. Another commenter suggested that there is nothing special from a technical perspective of 500 ppmv surface concentration that should drive a step function change in correcting for emissions and surface oxidation, as proposed by the EPA. This commenter indicated that there is already uncertainty in the gas collection efficiencies and that including the proposed surface methane concentration term simply adds to the uncertainty. The commenter recommended mandating the use of lower collection efficiencies when there is evidence of a high number of exceedances or a high surface methane concentration, rather than adding the surface methane 23 Abichou, T., J. Clark, and J. Chanton. 2011. ‘‘Reporting central tendencies of chamber measured surface emission and oxidation.’’ Waste Management, 31: 1002–1008. https://doi.org/ 10.1016/j.wasman.2010.09.014. 24 Abedini, A.R. 2014. Integrated Approach for Accurate Quantification of Methane Generation at Municipal Solid Waste Landfills. Ph.D. thesis, Dept. of Civil Engineering, University of British Columbia. 25 Lando, A.T., H. Nakayama, and T. Shimaoka. 2017. ‘‘Application of portable gas detector in point and scanning method to estimate spatial distribution of methane emission in landfill.’’ Waste Management, 59: 255–266. https://doi.org/10.1016/ j.wasman.2016.10.033. 26 Hettiarachchi, H., E. Irandoost, J.P. Hettiaratchi, and D. Pokhrel. 2023. ‘‘A field-verified model to estimate landfill methane flux using surface methane concentration measurements.’’ J. Hazard. Toxic Radioact. Waste, 27(4): 04023019. https:// doi.org/10.1061/JHTRBP.HZENG-1226. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 concentration term to equations HH–6, HH–7, and HH–8. This commenter also cited the work of Dr. Tarek Abichou (Kormi, et al., 2017 and 2018) for using surface concentration measurements to estimate emissions.27 28 Response: After considering comments received and reviewing additional studies, including those cited by the commenters, we are not taking final action on the proposed surfaceemissions monitoring correction term at this time.29 Upon review of the literature studies cited by one commenter (Abichou, et al., 2011; Abidini, 2014; Lando, et al., 2017; Hettiarachchi, et al., 2023), we confirmed that there is significant variability in measured surface concentrations and methane emissions flux across different landfills. The proposed correction factor, attributed to Heroux, et al. (2010),30 was the smallest of the correlation factors found across the other cited literature studies we reviewed. Based on a preliminary review of the additional study data, a more central tendency estimate of the correction factor term would be four to six times higher than the correction term proposed. Due to the high uncertainty in the proposed correction factor, we are assessing whether the correction term proposed for equations HH–6, HH–7, and HH–8 is the most appropriate method for developing a site-specific correction for the overall gas collection efficiency for reporters under subpart HH. The approach presented by Kormi, et al. (2017, 2018) uses a Gaussian plume model in conjunction with surface methane concentration measurements to estimate emissions. This approach appears too complex to incorporate into subpart HH. We are also evaluating other direct measurement technologies for assessing more accurate, landfill-specific gas collection efficiencies. Therefore, we decided not to take final action on the 27 Kormi, T., N.B.H. Ali, T. Abichou, and R. Green. 2017. ‘‘Estimation of landfill methane emissions using stochastic search methods.’’ Atmospheric Pollution Research, 8(4): 597–605. https://dx.doi.org/10.1016/j.apr.2016.12.020. 28 Kormi, T., et al. 2018. ‘‘Estimation of fugitive landfill methane emissions using surface emission monitoring and Genetic Algorithms optimization.’’ Waste Management 2018, 72: 313–328. https:// dx.doi.org/10.1016/j.wasman.2016.11.024. 29 Irandoost, E. (2020). An Investigation on Methane Flux in Landfills and Correlation with Surface Methane Concentration (Master’s thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca. https://hdl. handle.net/1880/111978. 30 He ´ roux, M., C. Guy and D. Millette. 2010. ‘‘A statistical model for landfill surface emissions.’’ J. of the Air & Waste Management Assoc. 60:2, 219– 228. https://doi.org/10.3155/1047-3289.60.2.219. PO 00000 Frm 00055 Fmt 4701 Sfmt 4700 31855 proposed correction term for equations HH–6, HH–7, and HH–8 at this time while we consider and evaluate other options. The EPA will continue to review additional information on existing and advanced methodologies and new literature studies and consider ways to effectively incorporate these methods and data in future revisions under subpart HH for estimating annual emissions. Comment: Numerous commenters cited studies suggesting that subpart HH underestimates the actual methane emissions released from landfills.31 32 These commenters noted that the underestimation in subpart HH emissions is primarily due to high default gas collection efficiencies in subpart HH. Two commenters asserted that gas collection efficiencies over 90 percent should not be used. One of these commenters noted that despite its own two-year study indicating otherwise, the EPA uses a 95 percent collection efficiency for landfills with final covers.33 Two commenters opposed the EPA’s use of the Maryland landfill data to support the proposed 10percentage point decrease in landfill gas collection efficiencies, noting that these gas collection efficiencies were calculated based on modeled methane generation rather than actual methane emissions measurements. One commenter further suggested that the Maryland study was not properly peerreviewed and is not suitable for use by the EPA in rulemaking according to the EPA’s Summary of General Assessment Factors For Evaluating the Quality of Scientific and Technical Information (hereinafter referred to as ‘‘General Assessment Factors’’).34 The commenter further stated that the Maryland study is based on a small subset of landfills that is likely not representative of the sector and the EPA’s reliance on that study to support a change to the default collection efficiency table (table HH–3 31 Oonk, H., 2012. ‘‘Efficiency of landfill gas collection for methane emissions reduction.’’ Greenhouse Gas Measurement and Management, 2:2–3, 129–145. https://doi.org/10.1080/20430779. 2012.730798. 32 Nesser, H., et al., 2023. ‘‘High-resolution U.S. methane emissions inferred from an inversion of 2019 TROPOMI satellite data: contributions from individual states, urban areas, and landfills.’’ EGUsphere [preprint], https://doi.org/10.5194/ egusphere-2023-946. 33 ARCADIS, 2012. Quantifying Methane Abatement Efficiency at Three Municipal Solid Waste Landfills; Final Report. Prepared for U.S. EPA, Office of Research and Development, Research Triangle Park, NC. EPA Report No. EPA/600/R–12/ 003. January. https://nepis.epa.gov/Exe/ZyPDF.cgi/ P100DGTB.PDF?Dockey=P100DGTB.PDF. 34 Available at https://www.epa.gov/sites/default/ files/2015-01/documents/assess2.pdf. Accessed January 9, 2024. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31856 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations to subpart HH) is inappropriate and will lead to inaccurate reporting of GHG emissions from the sector. This commenter stated that the EPA should continue to rely on the gas collection efficiencies recommended in the Solid Waste Industry for Climate Solutions (‘‘SWICS’’) white paper entitled Current MSW Industry Position and State-of-thePractice on LFG Collection Efficiency, Methane Oxidation, and Carbon Sequestration in Landfills.35 According to the commenter, the SWICS white paper is more comprehensive and relevant than the Maryland study. The commenters noted that the SWICS white paper is being revised and encouraged the EPA to delay revisions to the gas collection efficiency until the revised SWICS white paper is released. Response: We reviewed the various studies cited by commenters, including available versions of the SWICS white paper. Upon review of these papers and comments received, we maintain our position that the historical collection efficiencies are overstated and that it is appropriate to apply the lower collection efficiency to all landfills. In our review of the SWICS white paper, which was the basis for the historical gas collection efficiencies, we noted that data were omitted due to poor operation of gas collection system. Thus, we consider the historical gas collection efficiencies to be representative of ideal gas collection efficiencies. In our proposal, we required facilities that conduct surface-emission monitoring data to apply a correction factor that would reduce the overall collection efficiency, clearly indicating that we thought the current collection efficiencies are overstated, even for regulated landfills. While we expected that the surface emission correction factor would result in lower emissions than those calculated using the 10percentage point decrease in collection efficiency, based on our review of other studies correlating surface methane concentrations with methane flux, a more central tendency correlation factor is projected to yield emissions similar to a 10-percentage point decrease in collection efficiency. All the measurement study data we reviewed suggests that current GHGRP collection efficiencies are overstated on average by 10-percentage points or more (Duan, et al., 2022 and Nesser, et al., 2023).36 In reviewing the data from Nesser, et al. (2023), including the supplemental information,37 we found that all 38 landfills for which gas collection systems were reported were subject to the NSPS or EG. Comparing the gas collection efficiencies directly reported in the GHGRP, 35 of the 38 landfills had lower or similar measured gas collection efficiencies to those reported in subpart HH. With a 10-percentage point decrease in the default gas collection efficiencies, measured gas collection efficiencies were still at least 10percentage points lower for 20 of the 38 landfills, approximately equivalent for 13 landfills, and only higher than subpart HH proposed lower default collection efficiencies for 5 of the landfills. Similar low average collection efficiencies were noted by Duan, et al., (2022). Therefore, based on direct measurement data for landfills, we determined it is appropriate to finalize the lower default gas collection efficiencies and apply the lower gas collection efficiency for all landfills. While the Maryland study data suggests that the gas collection efficiency for voluntary systems may be lower than for regulated gas collection systems, we agree with commenters that these gas collection efficiencies are based on modeled generation rather than measured emissions. The DOC values for individual landfills can vary significantly and the differences observed could be due to differences in the wastes managed at the different Maryland landfills. We could not identify direct measurement study data by which to support further reductions in gas collection efficiencies for voluntary gas collection systems. Therefore, we are providing a single set of gas collection efficiencies for subpart HH reporters to use. In conclusion, we are finalizing gas collection efficiencies that are lower than those historically provided in subpart HH by 10-percentage points based on comments received and review of recent landfill methane emission measurement studies for landfills with gas collection systems. We had proposed these collection efficiencies for facilities not conducting surface emission monitoring, but we are now finalizing these lower gas collection efficiencies for all landfills. 35 SCS Engineers. 2009. Current MSW Industry Position and State-of-the-Practice on LFG Collection Efficiency, Methane Oxidation, and Carbon Sequestration in Landfills. Prepared for Solid Waste Industry for Climate Solutions (SWICS). Version 2.2. https://www.scsengineers.com/wp-content/ uploads/2015/03/Sullivan_SWICS_White_Paper_ Version_2.2_Final.pdf. 36 Duan, Z., Kjeldsen, P., & Scheutz, C. (2022). Efficiency of gas collection systems at Danish landfills and implications for regulations. Waste management (New York, N.Y.), 139, 269–278. https://doi.org/10.1016/j.wasman.2021.12.023. 37 See https://egusphere.copernicus.org/preprints/ 2023/egusphere-2023-946/egusphere-2023-946supplement.pdf. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00056 Fmt 4701 Sfmt 4700 Comment: Several commenters provided input on the proposed revisions to equations HH–6 through HH–8 to subpart HH to capture emissions from other large release events. Two commenters suggested that the EPA should require monitoring of both the pilot light and flow rate and that the ‘‘fDest’’ term should be excluded during any period the combustion device is not operating properly. The commenters specified that ‘‘fDest’’ should be excluded during any period when the reporter has operational data indicating that the combustion device is not operating according to manufacturer specifications or when the reporter has received credible monitoring data showing an unlit or malfunctioning control device. One commenter stated that the proposed revisions would be difficult to implement and tend to capture very limited or marginal data. The commenter asserted that gas collection systems by nature require constant adjustment of temperature, pressure, and other parameters or may be subject to frequent repairs that would not be expected to affect the overall control efficiency. The commenter asked the EPA to remove ‘‘normally’’ from the first sentence of the proposed definition of ‘‘fRec’’ and remove ‘‘or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances,’’ from the second sentence. The commenter also expressed concerns regarding how the proposed revisions to ‘‘fDest’’ applies to flares, stating that a large portion of landfill controls use open flares, or are equipped with automatic shutoffs, which have no parameters for monitoring effective operation other than the presence of a flame. The commenter requested the sentence addressing the pilot flame (‘‘For flares, times when there is no pilot flame present must be excluded from the annual operating hours for the destruction device.’’) be removed from the proposed revision of ‘‘fDest,’’ because it is confusing, unnecessary, and technically incorrect, as a pilot is typically only required during startup. One commenter also requested the EPA remove the phrase ‘‘. . . as measured at the nth measurement location’’ from the first sentence of ‘‘fDest’’ description; the commenter stated the text adds confusion by implying that the time gas is sent to the nth measurement location is equal to the time gas is sent to the control device, which may be incorrect for measurement locations with more than one control device. The commenter also E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations proposed a definition striking out ‘‘The annual operating hours for the destruction device should include only those periods when flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation.’’ The commenter added that because flares and other destruction devices are designed with fail-closed valves or other devices to prevent venting of gas when they are not operating, applying the definition as written overestimates emissions when a measurement location has more than one destruction device and all devices are not operating at the same time. Response: The EPA agrees with the commenters regarding monitoring the flow rate of the landfill gas; however, a change to the proposed rule is not necessary in this case as the continuous monitoring of the gas flow is already required in 40 CFR 98.343. The EPA disagrees with the comment that ‘‘EPA should likewise specify that fDest must be excluded during any period when the pilot light and flow rate are not meeting manufacturer specifications for complete combustion.’’ Adding this specification to the rule is not necessary as the revision to the definition of fDest already accounts for this scenario. The proposed revision to the fDest definition in the supplemental proposal states, ‘‘The annual operating hours for the destruction device should include only those periods when flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation.’’ Thus, if the destruction device has manufacturer specifications for effective operation that are not met during its operation, the revision to the fDest definition requires those periods to be excluded in the hours for fDest. We will further evaluate how credible monitoring data may be defined and excluded from fDest in a future rulemaking. The EPA disagrees with the proposed edits to the definition of fRec, which are to remove the word ‘‘normally’’ from the first sentence and remove the phrase ‘‘or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances’’ from the second sentence. These edits would allow for all operating hours in the calculation regardless of how the system operated. We asked for comment on what set of parameters should be used to identify poorly operating periods and whether a threshold on the proportion of wells operating outside of their VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 normal operating variance should be included in the definition of fRec to define periods of poor performance. With regards to the commenters’ input on the definition of fDest, the EPA agrees with removing ‘‘as measured at the nth measurement location’’ from the first sentence of the definition as the commenter notes, ‘‘flares and other destruction devices are designed with fail-closed valves or other devices to prevent venting of gas when they are not operating, keeping that phrase can overestimate emissions when a measurement location has more than one destruction device and all devices are not operating at the same time.’’ We are revising this sentence to remove ‘‘as measured at the nth measurement location.’’ We disagree with removing from the definition ‘‘For flares, times when there is no pilot flame present must be excluded from the annual operating hours for the destruction device.’’ Instead, we are revising this sentence to read ‘‘For flares, times when there is no flame present must be excluded from the annual operating hours for the destruction device.’’ We believe the lack of a flame is an indication the flare is not operating effectively. Lastly, we disagree with removing the sentence, ‘‘The annual operating hours for the destruction device should include only those periods when flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation.’’ We believe this sentence is necessary to ensure the calculation of fDest represents proper operation of the destruction device. Comment: We received several comments regarding the revised DOC values. Some commenters supported lowering of the default DOC for bulk waste from 0.20 to 0.17, citing similar findings in a 2019 Environmental Research and Education Foundation (EREF) study.38 These commenters generally opposed the proposed default value of 0.27 for bulk MSW (excluding inerts and construction and demolition (C&D) waste) and the proposed default value of 0.32 for uncharacterized wastes and recommended the use of either the value of 0.19 from the EREF report or the 0.17 value for bulk wastes for these other general waste categories. According to these commenters, the EPA’s method for determining the DOC 38 The Environmental Research & Education Foundation (2019). ‘‘Analysis of Waste Streams Entering MSW Landfills: Estimating DOC Values & the Impact of Non-MSW Materials.’’ Available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424. PO 00000 Frm 00057 Fmt 4701 Sfmt 4700 31857 for bulk MSW (excluding inerts and C&D waste) does not comport with how landfills characterize and manage input waste streams, and the high default DOC value for bulk MSW makes the modified bulk MSW option unusable. Other commenters opposed the proposed reduction in bulk waste and bulk MSW default DOC values, indicating that this will lead to lower emissions over the life of the landfill when research indicates emissions inventories of landfill emissions underestimate actual emissions. One commenter referenced a paper (Bahor, et al., 2010) that, according to the commenter, validated the default DOC of MSW to be 0.20.39 Other commenters noted that many landfill reporters were taking advantage of the composition method by only reporting inerts and uncharacterized wastes. These commenters supported the proposed default value of 0.32 for uncharacterized wastes. Response: The EPA included a DOC of 0.20 for bulk waste in subpart HH because the data we reviewed circa 2000 to 2010 indicated that was the best fit DOC value.40 As noted in the memorandum ‘‘Modified Bulk MSW Option Update’’ included in Docket ID. No. EPA–HQ–OAR–2019–0424, we have seen a significant decrease in the percentage of paper and paperboard products being landfilled due to increased recycling of these waste streams. This change in the composition of MSW landfilled supports and confirms the drop in DOC from 0.20 to 0.17 over the time period between 2005 and 2011. With respect to the Bahor, et al. (2010) study, it appears that the HHV measurement data was made using data from 1996 to 2006, with biogenic correction factors developed over 2007 and 2008. Based on the timing of the measurements made, agreement with the DOC value of 0.20 is not surprising and consistent with the findings by which we originally used a default DOC value of 0.20. We specifically sought to reassess the average DOC values considering more recent data to account for potential changes in DOC values over the past decade. Based on our analysis, an average DOC value of 0.17 provides a better fit with current landfill practices. Therefore, we are finalizing a revision of the default DOC value to 39 Bahor, Brian, et al. 2010. ‘‘Life-cycle assessment of waste management greenhouse gas emissions using municipal waste combustor data.’’ Journal of Environmental Engineering 136.8 (2010): 749–755. https://doi.org/10.1061/(ASCE)EE.19437870.0000189. 40 RTI International (2004). Solid Waste Inventory Support—Review Draft: Documentation of Methane Emission Estimates. Prepared for U.S. EPA, Office of Atmospheric Programs, Washington, DC. September 29. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31858 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 0.17 as proposed. However, we note that the proposed revision was not clear regarding how the new DOC value should be incorporated into the facility’s emissions estimate. Some reporters may only begin applying the new DOC value to new wastes being disposed of in 2025 and later years. Other reporters may opt to revise the DOC value for all wastes disposed of in the landfill for all previous disposal years. This could lead to significant discrepancies between emissions reported by reporters with similar landfills and also between the emissions reported for different years by a given reporter. As noted in this discussion, we expect that wastes disposed of prior to 2010 are best characterized using a default DOC value of 0.20 and that wastes disposed of in 2010 and later years are best characterized using a default DOC of 0.17. Therefore, while we are finalizing a revision in the default bulk waste DOC value to 0.17, we are also finalizing clarifications to these revisions to incorporate these revisions consistently across reporters and consistent with the timeframe where the reduction in DOC occurred. Specifically, we are maintaining the historic DOC value of 0.20 for historic disposal years (prior to 2010) and, starting with RY2025, requiring the use of the revised DOC value of 0.17 for disposal years 2010 and later (see memorandum ‘‘Revised Analysis and Calculation of Optimal k values for Subpart HH MSW Landfills Using a 0.17 DOC Default and Timing Considerations’’ available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424). With respect to the proposed DOC value for bulk MSW (excluding inerts and C&D waste), the approach we used to develop the proposed DOC value is consistent with the approach we used when we originally developed and provided the modified bulk waste option following consideration of comments received (75 FR 66450, October 28, 2010). This option was specifically provided to address comments that the waste composition option was too detailed for most landfill operators to use and that landfill operators should have the opportunity to characterize some of the waste received as inerts under the bulk waste option. Because the DOC values for bulk waste option were derived based on the full quantity of waste disposed at landfills, that DOC value for bulk waste intrinsically includes inerts. Therefore, we sought to develop a representative MSW DOC value that excludes inerts for use in the modified bulk MSW option. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 We disagree that this makes the modified bulk waste option inaccurate or unusable. On the contrary, we find that using the bulk waste DOC value in the modified bulk MSW option would be less accurate for predicting the CH4 generation for the modified bulk MSW option because the DOC value for bulk waste was determined by the full quantity of waste disposed at landfills including inerts and C&D waste. We also agree with commenters that some reporters are misusing the waste composition option in order to separately account for inerts but then use the bulk waste DOC value for the rest of the MSW. We conducted a multivariant analysis to project the DOC of uncharacterized MSW in landfills for which reporters used the waste composition method and the DOC for this uncharacterized waste was estimated to be 0.32. This agrees well with the proposed DOC value for bulk MSW of 0.27 and confirms that, when facilities separately report inert waste quantities, the DOC for the remaining MSW (excluding inerts and C&D waste) is much higher than suggested by some of the commenters. Consequently, we concluded that our proposed values of 0.27 for bulk MSW (excluding inerts and C&D waste) and 0.32 for uncharacterized waste should be finalized as proposed. Similar to our clarification regarding how the revision in bulk waste DOC must be implemented, we are finalizing requirements to use the current bulk MSW (excluding inerts and C&D waste) DOC value of 0.31 for historic disposal years (prior to 2010) and requiring the use of the revised bulk MSW (excluding inerts and C&D waste) DOC value of 0.27 for disposal years 2010 and later, consistent with the timeline for which these values were determined. Because we have no method to indicate a change in DOC for uncharacterized wastes, we are requiring the use of the new DOC for uncharacterized waste using the composition option of 0.32 for all years for which the composition option was used. We also disagree with commenters that having a high bulk MSW default DOC value makes the modified bulk MSW method unusable. Based on waste characterization data as reported for RY2022, approximately 23 percent use the modified bulk MSW method, which suggests a quarter of the reports find the modified bulk MSW option useful. While this option was specifically provided for landfills that accept large quantities of C&D waste or inert waste streams, we disagree that its use should be restricted to that scenario. There is PO 00000 Frm 00058 Fmt 4701 Sfmt 4700 significant variability in the DOC of bulk waste from landfill to landfill. There are many cases when the quantity of landfill gas recovered exceeds the modeled methane generation rates. This is a clear indication that the default DOC (and/or k value) is too low. For reporters with high actual CH4 generation rates, as noted by the quantity of CH4 recovered at the landfill, we find that the use of the modified bulk MSW option is appropriate for these reporters and would likely provide a more accurate estimate of modeled CH4 generation, even if these reporters do not have large quantities of inert or C&D wastes. We encourage reporters that have CH4 recovery rates exceeding their modeled CH4 generation rates to evaluate and use, as appropriate, the modified bulk MSW or waste composition options in order to more accurately estimate modeled methane generation. Comment: Several comments supported revisions to decay rate constants (k values) that more closely match the IPCC recommendations. Other comments were critical of the revisions, suggesting the proposed k values were too high. One commenter noted that the original k values were developed using a separate analysis considering the use of the CH4 generation potential (Lo, analogous to the DOC input for the first order decay model used in subpart HH). The commenter noted that optimizing k and DOC values simultaneously can lead to extreme and unrealistic values because an error in one value causes an offsetting error in the other. The commenter also stated that the EPA allowed an extremely wide range for the ‘‘optimized’’ k values (e.g., 0.001 to 0.400 for dry climates) and should have constrained the k values to more realistic values. The commenter also suggested that the EPA rely on its own research as published in PLoS ONE (Jain et al., 2021).41 Finally, the commenter suggested that multivariant analysis was not peer-reviewed and therefore does not appear to comply with the General Assessment Factors. Response: The EPA reviewed the documentation supporting the existing DOC and k value defaults used for subpart HH (RTI International, 2004). Importantly, the memorandum documents that the development of the DOC and k values utilized a two-step process. The first step was a 41 Jain, P., et al. 2021. ‘‘Greenhouse gas reporting data improves understanding of regional climate impact on landfill methane production and collection.’’ PLoS ONE, at 1–3, 10–11 (Feb. 26, 2021), available at https://journals.plos.org/ plosone/article?id=10.1371/journal.pone.0246334. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations multivariant analysis, similar to the analysis conducted in 2019 (McGrath et al., 2019), which was used to determine an optimal DOC value. The second step was to determine optimal k values for each precipitation range using the optimal DOC value from the multivariant analysis. At proposal, we used the DOC and k values determined directly from the multivariant analysis. After consideration of the comments received and the approach used historically, we determined that it would be more appropriate to determine optimal k values once the default DOC value is established. We agree with the commenter that using a fixed DOC value (set at the proposed bulk waste DOC value of 0.17), we expect that the optimal k values in a single-variable analysis would have less variability and better predict methane generation across landfills when using the revised DOC default. Therefore, we conducted this second step of the analysis using the original data set for facilities using the bulk waste approach to determine the optimal k values for these landfills, given a default DOC value of 0.17 (the bulk waste DOC value recommended in the McGrath et al. (2019) memo based on the multivariant analysis). We also reviewed additional literature to assess reasonable ranges for k values. We found that the lowest allowed k value of 0.001 yr¥1 was unrealistic and much lower than any k value reported in the literature. We identified some studies suggesting a k value of 0.4 yr¥1 is possible for wet landfills (or landfills using leachate recirculation). After our review of the additional literature, we revised the allowable k value range from 0.001–0.4 yr¥1 to 0.007–0.3 yr¥1. The results of applying this second step of the analysis, consistent with the approach used previously to develop 31859 default k values, indicate that the optimal k values for dry, moderate, and wet climates were 0.033, 0.067, and 0.098 yr¥1, respectively (see memorandum ‘‘Revised Analysis and Calculation of Optimal k Values for Subpart HH MSW Landfills Using a 0.17 DOC Default and Timing Considerations’’ available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424). These values are lower than those developed from the multivariant analysis, but still significantly higher than the current defaults in subpart HH. These values also align well with IPCC recommended k value ranges for moderately decaying waste and the k values reported by Jain, et al. (2021). Table 5 of this preamble presents a comparison of the old subpart HH and revised k values with the values recommended by the IPCC and Jain, et al. (2021). TABLE 5—COMPARISON OF FINALIZED DECAY RATE CONSTANTS (k VALUES IN YRS¥1) BY PRECIPITATION RANGE Historic subpart HH and inventory default decay value (k) Precipitation zone lotter on DSK11XQN23PROD with RULES2 Dry (<20 inches/year) ...................................................................... Moderate (20–40 inches/year) ......................................................... Wet (>40 inches/year) ..................................................................... Similar to the incorporation of the new DOC values, we note that the proposed revision was not clear regarding how the new k values for bulk waste under the ‘‘Bulk waste option’’ and bulk MSW under the ‘‘Modified bulk MSW option’’ should be incorporated into the facility’s emissions estimate. While we are finalizing revisions for the default bulk waste k values for dry, moderate, and wet climates as 0.033, 0.067, and 0.098 yr¥1, respectively, we are also finalizing clarifications to these revisions to incorporate these revisions consistently across reporters and consistent with the timeframe where the reduction in DOC occurred. Specifically, starting in RY2025, we are maintaining the historic k values of 0.20, 0.038, and 0.057 yr¥1 for historic disposal years (prior to 2010) and requiring the use of the revised k values of 0.033, 0.067, and 0.098 yr¥1 for disposal years 2010 and later. We are finalizing requirements under the modified bulk waste MSW option to use the current bulk MSW (excluding inerts and C&D waste) k values of 0.02 to 0.057 yr¥1 for historic disposal years (prior to 2010) and requiring the use of the revised bulk VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 0.02 0.038 0.057 Revised subpart HH default decay value (k) 0.033 0.067 0.098 MSW (excluding inerts and C&D waste) k values of 0.033 to 0.098 yr¥1 for disposal years 2010 and later, consistent with the timeline for which these values were determined. Because we have no method to indicate a change in k value for uncharacterized wastes, we are requiring the use of the new k values for uncharacterized waste using the composition option of 0.033 to 0.098 for all years for which the composition option was used. With respect to compliance with the General Assessment Factors, we considered a wide variety of information, including peer-reviewed material, when developing our proposed and final k values. While our technical support documents are not formally peer reviewed at proposal, we consider the proposal/public review process to be an adequate forum for public review of our analysis and conclusions. After considering the public comments received, we revised our analysis to more closely match the original approach used to determine default k values. We also adjusted our allowable range for k values based on public comment and additional literature review. All information we have PO 00000 Frm 00059 Fmt 4701 Sfmt 4700 IPCC default decay value (k) ranges for moderately decaying waste 0.04–0.05 0.04–0.1 0.07–0.17 Jain, et al. (2021), recommended k value (and 95% confidence range) 0.043 (0.033–0.054) 0.074 (0.061–0.088) 0.090 (0.077–0.105) reviewed indicate that the historic subpart HH k values are too low and that the values we determined in our reanalysis of the data will provide improved methane generation estimates. For these reasons, we are finalizing revised k values for subpart HH of 0.033, 0.067, and 0.098 yr¥1 for dry, moderate, and wet climates, respectively. These k values apply to bulk waste, bulk MSW, and uncharacterized MSW, as proposed. U. Subpart OO—Suppliers of Industrial Greenhouse Gases We are finalizing several amendments to subpart OO of part 98 (Suppliers of Industrial Greenhouse Gases) as proposed. Section III.U.1. of this preamble discusses the final revisions to subpart OO. The EPA received comments on the proposed revisions to subpart OO which are discussed in section III.U.2. of this preamble. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the revisions to subpart OO as described in section VI. of this preamble. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31860 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 1. Summary of Final Amendments to Subpart OO This section summarizes the final amendments to subpart OO. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart OO can be found in this section and section III.U.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. The EPA is finalizing several revisions to subpart OO of part 98 that will improve the quality of the data collection under the GHGRP. First, we are adding a requirement at 40 CFR 98.417(c)(7) for bulk importers of F– GHGs to include, as part of the information required for each import in the annual report, the customs entry number. The customs entry number is provided as part of the U.S. Customs and Border Protection (CBP) Form 7501: Entry Summary and is assigned for each filed CBP entry for each shipment. The EPA has made one minor clarification from proposal. We initially proposed the requirement as the ‘‘customs entry summary number’’; the final rule modifies 40 CFR 98.416(a)(7) to clarify the requirement to the ‘‘customs entry number,’’ which is associated with the CBP Form 7501, ‘‘Entry Summary.’’ As proposed, we are adding a reporting requirement at 40 CFR 98.416(k) that suppliers of N2O, saturated PFCs, SF6, and fluorinated HTFs identify the end uses for which the N2O, SF6, saturated PFC, or fluorinated HTF is used and the aggregated annual quantities of N2O, SF6, each saturated PFC, or each fluorinated HTF transferred to each end use, if known. As discussed in the proposed rules, this requirement is based on a similar requirement in subpart PP to part 98 (Suppliers of Carbon Dioxide) and is intended to provide additional insight into the identities and magnitudes of the uses of these compounds, which are currently less well understood than those of other industrial GHGs such as HFCs, although the GWP-weighted totals supplied are relatively large. The EPA is also finalizing a clarification to the reporting requirements for importers and exporters of F–GHGs, F–HTFs, or N2O, to revise the required reporting of ‘‘commodity code,’’ which is required for importers at 40 CFR 98.416(c)(6) and for exporters at 40 CFR 98.416(d)(4), to clarify that reporters should submit the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Harmonized Tariff System (HTS) code for each F–GHG, F–HTF, or N2O shipped. Reporters will enter the full 10-digit HTS code with decimals, to extend to the statistical suffix, as it was entered on related customs forms. See section III.S. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on the EPA’s rationale for these changes. As discussed in section III.A.1.b. of this preamble, we are finalizing related revisions to the definition of ‘‘fluorinated HTF,’’ previously included in subpart I of part 98 (Electronics Manufacturing), and to move the definition to subpart A of part 98 (General Provisions), to harmonize with the changes to subpart OO. Finally, we are finalizing revisions to 40 CFR 98.416(c) and (d) to clarify that certain exceptions to the reporting requirements for importers and exporters are voluntary, consistent with our original intent. To implement this change, we are finalizing revisions to insert ‘‘importers may exclude’’ between ‘‘except’’ and ‘‘for shipments’’ in the first sentence of § 98.416(c) and (d), deleting the ‘‘for.’’ We are also finalizing revisions to clarify that imports and exports of transshipments will both have to be either included or excluded for any given importer or exporter, and we are finalizing a similar clarification for heels. These changes ensure that importers and exporters treat the exceptions consistently. See section III.K. of the preamble to the 2023 Supplemental Proposal for additional information on these revisions and their supporting basis. In the 2023 Supplemental Proposal, the EPA proposed a requirement at 40 CFR 98.416(c) for bulk importers of F– GHGs to provide, for GHGs that are not regulated substances under 40 CFR part 84 (Phasedown of Hydrofluorocarbons), copies of the corresponding U.S. CBP entry forms (e.g., CBP Form 7501) in their annual report. Following consideration of public comments received on a similar proposed revision to subpart QQ of part 98 (Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment and Closed-Cell Foams), including concerns regarding the availability of this information and the potential burden of submitting large volumes of entry forms, the EPA is not taking final action on the proposed revision to subpart OO. See section III.W. of this preamble for additional information. PO 00000 Frm 00060 Fmt 4701 Sfmt 4700 2. Summary of Comments and Responses on Subpart OO This section summarizes the major comments and responses related to the proposed amendments to subpart OO. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart OO. Comment: One commenter requested that we clarify that chemical supply ‘‘end use’’ refers to industry category only, such as electronics or semiconductor use, and does not refer to more specific uses. The commenter recommended that specific purchases and purposes of chemical use should be considered industry confidential business information and therefore protected from public disclosure. The commenter also noted that chemical suppliers or distributors do not typically have visibility to end use, particularly specific end use categories. Response: As discussed in section VI. of this preamble, we are planning to finalize our proposed determination that the two new subpart OO data elements (the end use(s) to which the N2O, SF6, each PFC, or each fluorinated HTF is transferred and the aggregated annual quantity of the GHG that is transferred to that end use application) are ‘‘Eligible for Confidential Treatment.’’ This will protect the data from public disclosure. Regarding suppliers’ knowledge of the uses of compounds within each industry, suppliers are required to report the end uses only ‘‘if known.’’ For N2O, SF6, and saturated PFCs, the end uses that we identified in the proposed rule coincided with individual industries and not specific uses within those industries. For fluorinated HTFs, the end uses that we identified in the proposed rule coincided with some specific uses within industries, such as cleaning versus temperature control within the electronics industry. This was because different end uses, even within the same industry, have different emission patterns, which affect the relationship between emissions and consumption of these compounds. (For example, end uses that quickly emit the F–HTF, such as cleaning, are expected to have emissions that are close to consumption, whereas end uses that store the F–HTF, such as process cooling, may have emissions that are less than half of consumption.) However, the electronics industry, unlike other industries that E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 use F–HTFs, reports its F–HTF emissions to EPA. Thus, in the subpart OO electronic reporting form, we are planning to list ‘‘electronics manufacturing’’ (including manufacturing of semiconductors, MEMS, photovoltaic cells, and displays), and not specific uses within electronics manufacturing, among the end uses whose consumption of the fluorinated HTF will be reported. V. Subpart PP—Suppliers of Carbon Dioxide We are finalizing several amendments to subpart PP of part 98 (Suppliers of Carbon Dioxide) as proposed. This section discusses the final revisions to subpart PP. The EPA received comments on the proposed revisions to subpart PP. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA– HQ–OAR–2019–0424 for a complete listing of all comments and responses related to subpart PP. The EPA is finalizing several revisions to subpart PP to improve the quality of the data collected from this subpart. As proposed, we are adding new 40 CFR 98.420(a)(4) and a new definition to 40 CFR 98.6 to explicitly include direct air capture (DAC) as a capture option under subpart PP. Unlike conventional capture sources where CO2 is separated during the manufacturing or treatment phase of product stream, DAC captures CO2 from ambient air using aqueous or solid sorbents, which is then processed into a concentrated stream for utilization or injection underground. This final rule provides that DAC, ‘‘with respect to a facility, technology, or system, means that the facility, technology, or system uses carbon capture equipment to capture carbon dioxide directly from the air. DAC does not include any facility, technology, or system that captures carbon dioxide (1) that is deliberately released from a naturally occurring subsurface spring or (2) using natural photosynthesis.’’ The EPA is also finalizing an amendment to the definition of ‘‘carbon dioxide stream’’ in 40 CFR 98.6 to add ‘‘captured from ambient air (e.g., direct air capture)’’ to the definition so that it reads, ‘‘Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant or other industrial facility), captured from ambient air (e.g., direct air capture), or extracted from a carbon dioxide production well plus incidental associated substances either derived VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 from the source materials and the capture process or extracted with the carbon dioxide.’’ We are finalizing harmonizing changes to 40 CFR 98.422, 98.423, 98.426, and 98.427 to add references to DAC into the reporting requirements. The final rule also amends 40 CFR 98.426 as proposed to add additional reporting requirements in paragraph (i) to require DAC facilities to report the annual quantities and sources (e.g., nonhydropower renewable sources, natural gas, oil, coal) of on-site and off-site sourced electricity, heat, and combined heat and power used to power the DAC plant. These quantities must represent the electricity and heat used starting from the air intake at the facility and ending with the compressed CO2 stream (i.e., the CO2 stream ready for supply for commercial applications or, if maintaining custody of the stream, sequestration or injection of the stream underground). These quantities must be provided per energy source, if known. For electricity provided to the DAC plant from the grid, reporters must additionally provide identifying information for the facility and electric utility company. In addition, for on-site sourced electricity, heat, and combined heat and power, DAC facilities must indicate whether flue gas is also captured by the DAC process unit. These changes will aid the EPA in understanding this emerging technology at facilities that utilize DAC and in better understanding potential net emissions impacts associated with DAC facilities (particularly given that interest in DAC is primarily intended to be a carbon removal technology to achieve climate benefits). See section III.T. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on the EPA’s rationale for these changes. The EPA is finalizing two additional revisions to improve data quality. First, we are finalizing the addition of a data element to 40 CFR 98.426(f) that will require suppliers to report the annual quantity of CO2 in metric tons that is transferred for use in geologic sequestration with EOR subject to new subpart VV to part 98 (Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916). To inform the revision of the subpart PP electronic reporting form, the EPA also sought comment on potential end use applications to add to 40 CFR 98.426(f), such as algal systems, chemical production, and mineralization processes, such as the production of cements, aggregates, or bicarbonates. However, because 40 CFR 98.426(f) already includes a reporting PO 00000 Frm 00061 Fmt 4701 Sfmt 4700 31861 category for ‘‘other,’’ the existing rule already provides flexibility for this reporting, and we are not taking final action on the addition of specific enduse applications to 40 CFR 98.426 at this time. The EPA may consider the addition of other end-use applications in a future rulemaking. Second, the EPA is finalizing as proposed that 40 CFR 98.426(h) will apply to any facilities that capture a CO2 stream from a facility subject to 40 CFR part 98 and supply that CO2 stream to facilities that are subject to either subpart RR (Geologic Sequestration of Carbon Dioxide) or new subpart VV. The revised paragraph will no longer apply only to suppliers that capture CO2 from EGUs subject to subpart D (Electricity Generation), but also to suppliers that capture CO2 from any direct emitting facility that is subject to 40 CFR part 98 and transfer to facilities subject to subparts RR or VV. Reporters must provide the facility identification number associated with the facility that is the source of the captured CO2 stream, each facility identification number associated with the annual GHG reports for each subpart RR and subpart VV facility to which CO2 is transferred, and the annual quantity of CO2 transferred to each subpart RR and VV facility. See section III.L. of the preamble to the 2023 Supplemental Proposal for additional information. The EPA also requested comment on, but did not propose, expanding the requirement at 40 CFR 98.426(h) such that facilities subject to subpart PP would report transfers of CO2 to any facilities reporting under 40 CFR part 98, not just those subject to subparts RR and VV. This would include reporting the amount of CO2 transferred on an annual basis as well as the relevant GHGRP facility identification numbers. The EPA further requested comment on whether information regarding additional end uses would be available to facilities. Following consideration of public comments, we are not extending the reporting requirements at this time but may consider doing so in a future rulemaking. We are finalizing, with revisions, related confidentiality determinations for data elements resulting from the revisions to subpart PP as described in section VI. of this preamble. W. Subpart QQ—Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment and Closed-Cell Foams We are finalizing the amendments to subpart QQ of part 98 (Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged E:\FR\FM\25APR2.SGM 25APR2 31862 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 Equipment and Closed-Cell Foams) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.W.1. discusses the final revisions to subpart QQ. The EPA received several comments on proposed subpart QQ revisions which are discussed in section III.W.2. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the final revisions to subpart QQ, as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart QQ This section summarizes the final amendments to subpart QQ. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart QQ can be found in this section and section III.W.2. of this preamble. Additional rationale for these amendments are available in the preamble to the 2023 Supplemental Proposal. We are finalizing two revisions from the 2023 Supplemental Proposal. We are finalizing requirements for importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams to include, for each import and export, the HTS code (for importers, at 40 CFR 98.436(a)(7)) and the Schedule B code (for exporters, at 40 CFR 98.436(b)(7)) used for shipping each equipment type. These requirements are consistent with the final revisions to subpart OO of part 98 (Suppliers of Industrial Greenhouse Gases), which clarify that reporters should submit the HTS code for each shipment, as discussed in section III.U. of this preamble. See section III.S. of the preamble to the 2023 Supplemental Proposal for additional information on the EPA’s rationale for these changes. The EPA also proposed to revise 40 CFR 98.436 to add a requirement to include collecting copies of the U.S. CBP entry form (e.g., CBP form 7501) for each reported import, which are currently maintained as records under 40 CFR 98.437(a). Following consideration of public comments, the EPA is not taking final action on the proposed requirement to submit copies of each U.S. CBP entry form. See section III.W.2. of this preamble for a summary of the related comments and the EPA’s response. 2. Summary of Comments and Responses on Subpart QQ This section summarizes the major comments and responses related to the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 proposed amendments and supplemental amendments to subpart QQ. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA– HQ–OAR–2019–0424 for a complete listing of all comments and responses related to subpart QQ. Comment: Several commenters contested the EPA’s proposed requirements to collect a copy of the corresponding U.S. CBP entry form (e.g., Form 7501) for each reported import in 40 CFR 98.436. Some commenters asserted that the information available in the forms is currently provided electronically to CBP through the Automated Commercial Environment (ACE) and should be available to the EPA within the need for reporters to develop or submit copies. The commenters noted that this information should be sufficient to identify which entries are subject to data requirements under subpart QQ. Commenters recommended that the EPA should coordinate with CBP through established bodies (e.g., the Border Interagency Executive Council and Commercial Targeting and Analysis Center, to which the EPA already participates) to identify and utilize this data. One commenter specifically recommended that the EPA review the Entry Summary Line Detail Report, which would show the total quantity reported for entry summary lines by tariff number for the reported unit of measure. The commenters stated that such reports capture the actual data in CBP’s system, as filed by importers, and should be sufficient to ensure that the Agency is able to improve the verification and accuracy of the data it collects. One commenter expressed that if the EPA is unable to identify applicable entries through more efficient means, importers should only be asked to identify specific entry numbers that will allow the EPA to identify the applicable electronic submissions within ACE. Commenters objected to the implied submission of hard-copy entry records as an unnecessary administrative burden. Commenters stated that the proposed requirement runs counter to CBP’s longstanding effort to collect import data and documents electronically. One commenter stated that submittal of the border crossing document would necessitate a substantial amount of additional work and resources to comply, including gathering documentation from multiple sources prior to annual reporting. PO 00000 Frm 00062 Fmt 4701 Sfmt 4700 Another commenter noted that in some cases, importers could be required to file over 70,000 entries or forms. One commenter stated that this would require at least 1,300 manual searches for the appropriate forms for each entry. Commenters urged that this would be prohibitively expensive and burdensome. One commenter pointed out that this would require substantial modifications to automakers’ existing information systems and processes for their GHG and related reporting obligations. Other commenters noted that paper form requirements would obfuscate industry efforts to further automate their record-keeping and reporting systems. One commenter added that the increased volume of documentation would likely put much more pressure on businesses than they can manage based on the current requirement to file data by March 31st of the year following the reporting year. One commenter stated that the CBP forms would merely confirm the amount of foam board imported or exported and would not validate the F–GHG quantity which is the intent of the report. The commenter continued that, even if border documents were provided, it would be impossible for the EPA to validate the current reports as the calculations involved to provide the volume of F–gas per board foot would require detailed technical knowledge, including density of the foam board. Some commenters asserted that the entry form requirement runs counter to Executive Order 13659 and 19 U.S.C. 1411(d), as amended by sections 106 and 107 of the Trade Facilitation and Trade Enforcement Act of 2015, which advance the goal of providing for electronic transmission of import data and seek to eliminate the need for duplicative information submissions across U.S. government agencies with regulatory authority related to goods entered or imported into the United States. Other commenters questioned the EPA’s requirements to require reporting of the HTS) code for each type of precharged equipment or closed-cell foam imported and/or the Schedule B code for each type of pre-charged equipment or closed-cell foam exported. One commenter questioned whether the inclusion of both HTS codes and Schedule B codes is necessary for validation of the data that is currently collected, as all polystyrene foams use the same codes. The commenter urged that requiring more than one type of document would prove redundant in showing product type; be burdensome for manufacturers and for the EPA; and would not provide any additional E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 clarity or validation to the current report. Another commenter stated that only the border crossing document (which includes the customs tariff number, with the first six digits of an HTS and Schedule B number) should be required as part of the annual report. The commenter noted that these border crossing documents share highly sensitive information such as quantity and price, so should be handled securely. One commenter reiterated that all data proposed to be collected is, and would be, considered highly confidential business information. The commenter added that access to this type of information is restricted internally, which adds complexity to who could manage and deal with the processing of this documentation within facilities. Response: The EPA is revising the final rule to remove the requirement for reporters to submit copies of their U.S. CBP form 7501. Following consideration of comments received, it has been determined that annually reporting these documents could pose a significant burden for many reporters. Therefore, the EPA is not adopting the proposed data reporting requirement in the final rule. The EPA is finalizing the proposed requirement to report HTS codes (for imports) and Schedule B codes (for exports) to assist the Agency in verification of data. This requirement will allow the EPA to better compare reported GHGRP data with data from other government sources, specifically CBP records. As only one type of code (HTS or Schedule B) will be required based on whether the shipment is an import or export, this will not require the reporting of redundant information to the EPA. Furthermore, we are making ‘‘No Determination’’ of confidentiality for this data element. ‘‘No Determination’’ means that the EPA is not making a confidentiality determination through rulemaking at this time. If necessary, the EPA will evaluate and determine the confidentiality status of this data on a per-facility basis in accordance with the provisions of 40 CFR part 2, subpart B. X. Subpart RR—Geologic Sequestration of Carbon Dioxide We are finalizing amendments to subpart RR of part 98 (Geologic Sequestration of Carbon Dioxide) as proposed. This section discusses the substantive final revisions to subpart RR. The EPA received only one supportive comment for subpart RR. See the document ‘‘Summary of Public Comments and Responses for 2024 Final VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart RR. Additional rationale for these amendments is available in the preamble to the 2023 Supplemental Proposal. We are adding a definition for ‘‘offshore’’ to 40 CFR 98.449 to mean ‘‘seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.’’ This definition clarifies the applicability of subpart RR to offshore geologic sequestration activities, including on the outer continental shelf. Additional rationale for these amendments is available in the preamble to the 2023 Supplemental Proposal. Y. Subpart SS—Electrical Equipment Manufacture or Refurbishment We are finalizing several amendments to subpart SS of part 98 (Electrical Equipment Manufacture or Refurbishment) as proposed. In some cases, we are finalizing the proposed amendments with revisions. Section III.Y.1. of this preamble discusses the substantive final revisions to subpart SS. The EPA received several comments on the proposed revisions to subpart SS which are addressed in section III.Q.2. of this preamble. We are also finalizing as proposed confidentiality determinations for new data elements resulting from the revisions to subpart SS as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart SS This section summarizes the final amendments to subpart SS. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other final revisions to 40 CFR part 98, subpart SS can be found in this section and section III.Y.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal. a. Revisions To Improve the Quality of Data Collected for Subpart SS The EPA is finalizing several revisions to subpart SS to improve the quality of the data collected from this subpart. We are generally finalizing as PO 00000 Frm 00063 Fmt 4701 Sfmt 4700 31863 proposed revisions to the calculation, monitoring, and reporting requirements of subpart SS (at 40 CFR 98.452, 98.453, 98.454, and 98.456) to require reporting of additional F–GHGs as defined under 40 CFR 98.6, except electrical equipment manufacturers and refurbishers will not be required to report emissions of insulating gases with weighted average GWPs of one (1) or less. However, they will be required to report the quantities of insulating gases with weighted average GWPs of one or less, as well as the nameplate capacities of the associated equipment, that they transfer to their customers. To implement these revisions, we are finalizing revisions that redefine the source category at 40 CFR 98.450 to include equipment containing ‘‘fluorinated GHGs (F–GHG), including but not limited to sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs).’’ The changes also apply to the threshold in 40 CFR 98.451, which we are revising as discussed in section III.Y.1. of this preamble. Facilities also must consider additional F–GHGs purchased by the facility in estimating emissions for comparison to the threshold. The revisions to subpart SS include the addition of a new equation SS–1 in the reporting threshold at 40 CFR 98.451 (discussed in section III.Y.b. of this preamble) and a new equation SS–2 in the GHGs to report at 40 CFR 98.452. Equation SS–2 is also used in the definition of ‘‘reportable insulating gas,’’ discussed in this section of the preamble. We are also making minor revisions to equations SS–1 through SS– 6 (which we are renumbering as SS–3 through SS–8 to accommodate new equations SS–1 and SS–2) to incorporate the estimation of emissions from all F–GHGs within the existing calculation methodology. To account for the possibility that the same fluorinated GHG could be a component of multiple reportable insulating gases, we are inserting in the final rule a summation sign at the beginning of the right side of equation SS–3 to ensure that emissions of each fluorinated GHG i are summed across all reportable insulating gases j. In addition, we are updating the monitoring and quality assurance requirements to account for emissions from additional F–GHGs, and harmonizing revisions to the reporting requirements such that reporters account for the mass of each F–GHG at the facility level. We are also finalizing the proposed definition of ‘‘insulating gas’’ and adding the term ‘‘reportable insulating gas,’’ which is defined as ‘‘an insulating gas whose weighted average GWP, as calculated in equation SS–2, is greater E:\FR\FM\25APR2.SGM 25APR2 31864 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 than one. A fluorinated GHG that makes up either part or all of a reportable insulating gas is considered to be a component of the reportable insulating gas.’’ This term is intended to distinguish between insulating gases whose emissions must be reported under subpart SS and insulating gases whose emissions are not required to be reported under subpart SS (although, as noted above, the quantities of all insulating gases supplied to customers must be reported). In many though not all cases, we are also replacing occurrences of the proposed phrase ‘‘fluorinated GHGs, including PFCs and SF6’’ with ‘‘fluorinated GHGs that are components of reportable insulating gases.’’ In addition, we are finalizing revisions to add reporting of an ID number or descriptor for each insulating gas and the name and weight percent of each insulating gas reported. The EPA has also made one minor clarification from proposal. We initially proposed 40 CFR 98.456(u) to require reporting of an ID number or descriptor for each unique insulating gas. To clarify the applicability of this requirement for those gases mixed on-site, the final rule clarifies that facilities must report an ID number or other appropriate descriptor that is unique to the reported insulating gas, and for each ID number or descriptor reported, the name and weight percent of each fluorinated gas in the insulating gas. See section III.U.1. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. b. Revisions To Streamline and Improve Implementation for Subpart SS To account for changes in the usage of certain GHGs and reduce the likelihood that the reporting threshold will cover facilities with emissions well below 25,000 mtCO2e, we are generally finalizing revisions to the applicability threshold of subpart SS as proposed. (The one change is the introduction of the term ‘‘reportable insulating gas,’’ as described in this section III.Y. of the preamble.) The revisions remove the consumption-based threshold at 40 CFR 98.451 and instead require facilities to estimate total annual GHG emissions for comparison to the 25,000 mtCO2e threshold by introducing a new equation, equation SS–1. The equation SS–1 continues to be based on the total annual purchases of insulating gases, but establishes an updated comparison to the threshold, and accounts for the additional fluorinated gases reported by industry. Potential reporters are required to account for the total annual purchases of all reportable insulating VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 gases and multiply the purchases of each reportable insulating gas by the GWP for each F–GHG and the emission factor of 0.10 (or 10 percent). The final rule threshold methodology is more appropriate because it represents the actual fluorinated gases used by a reporter; these revisions also streamline the reporting requirements to focus Agency resources on the substantial emission sources within the sector. Additionally, the changes revise the inclusion of subpart SS in the existing table A–3 to subpart A. Because we are providing a method for direct comparison to the 25,000 mtCO2e threshold, we are removing subpart SS from table A–3 and including the subpart in table A–4 to subpart A. This will require facilities to determine applicability according to 40 CFR 98.2(a)(2) and consider the combined emissions from stationary fuel combustion sources (subpart C), miscellaneous use of carbonates (subpart U), and other applicable source categories. Including subpart SS in table A–4 to subpart A is consistent with other GHGRP subparts that use the 25,000 mtCO2e threshold included under 40 CFR 98.2(a)(2) to determine applicability. See section III.U.2. of the preamble to the 2022 Data Quality Improvements Proposal for additional information on these revisions and their supporting basis. 2. Summary of Comments and Responses on Subpart SS This section summarizes the major comments and responses related to the proposed amendments to subpart SS. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart SS. Comment: One commenter suggested redefining the definition of ‘‘insulating gas’’ to including any gas with a GWP greater than one and not any fluorinated GHG or fluorinated GHG mixture. The commenter urged that the proposed definition ignores other potential gases that may come onto the market that are not fluorinated but still have a GWP potential. The commenter stated that defining insulating gas under subpart SS to include any gas with a GWP greater than one used as an insulating gas and/ or arc quenching gas in electrical equipment would mirror the threshold implemented by the California Air Resources Board and would provide PO 00000 Frm 00064 Fmt 4701 Sfmt 4700 consistency for reporters across Federal and State reporting rules. Response: In the final rule, the EPA is not requiring electrical equipment manufacturers and refurbishers to report emissions of insulating gases with weighted average 100-year GWPs of one or less, but the EPA is requiring such facilities to report the quantities of insulating gases with GWPs of one or less, as well as the nameplate capacity of the associated equipment, that they transfer to their customers. Based on a review of the subpart SS data submitted to date, the EPA has concluded that excluding emissions of insulating gases with weighted average GWPs of one or less from reporting under subpart SS will have little effect on the accuracy or completeness of the GWP-weighted totals reported under subpart SS or under the GHGRP generally. Between 2011 and 2021, total SF6 and PFC emissions across all facilities reporting under subpart SS have ranged from 5 to 15 mt (unweighted) or 120,000 to 350,000 mtCO2e. At GWPs of one, these weighted totals would be equivalent to the unweighted quantities reported, which constitute approximately 0.004% (1/23,500) of the GWP-weighted totals. Even in a worst-case scenario where the annual manufacturer emissions of a very low-GWP insulating gas were assumed to equal the total quantity of that gas transferred from manufacturers to customers (implying an emission rate of 100%, higher than any ever reported under subpart SS), the total GWPweighted emissions reported under subpart SS would be considerably smaller than those reported under any other subpart: total unweighted quantities shipped to customers reported across all facilities to date have ranged between 196 and 372 mt. At GWPs of 1, these totals would fall well below the 15,000- and 25,000 mtCO2e quantities below which individual facilities are eventually allowed to exit the program under the off-ramp provisions of subpart A of part 98 (40 CFR 98.2(i)), as applicable. While the EPA is not requiring electrical equipment manufacturers and refurbishers to report their emissions of insulating gases with GWPs of one or less, the EPA is requiring such facilities to report the quantities of insulating gases with weighted average GWPs of one or less, as well as the nameplate capacity of the associated equipment, that they transfer to their customers. Tracking such transfers is important to understanding the extent to which substitutes for SF6 are replacing SF6 as an insulating gas, which will inform future policies and programs under provisions of the CAA. The EPA E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations anticipates that tracking transfers to customers will involve a lower burden than tracking emissions and other quantities in addition to transfers. lotter on DSK11XQN23PROD with RULES2 Z. Subpart UU—Injection of Carbon Dioxide We are finalizing the amendments to subpart UU of part 98 (Injection of Carbon Dioxide) as revised in the 2023 Supplemental Proposal. This section discusses the final revisions to subpart UU. The EPA received only one supportive comments on the proposed revision to subpart UU in the 2023 Supplemental Proposal. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart UU. The EPA initially proposed amendments to subpart UU in the 2022 Data Quality Improvements Proposal that were intended to harmonize with revisions to add new subpart VV to part 98 (Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916). Subpart VV is described further in section III.Z. of this preamble. However, we received comments on the 2022 Data Quality Improvements Proposal saying that the applicability of proposed subpart VV was unclear. The EPA subsequently reproposed revisions to 40 CFR 98.470 in the 2023 Supplemental Proposal. As described in sections III.O. of the preamble of the 2023 Supplemental Proposal, the EPA proposed, and is finalizing, revisions to § 98.470 of subpart UU of part 98 to clarify the applicability of each subpart when a facility quantifies their geologic sequestration of CO2 in association with EOR operations through the use of the CSA/ANSI ISO 27916:19 method. Specifically, we are clarifying that facilities with a well or group of wells that must report under subpart VV shall not also report data for those same wells under subpart UU. These changes also clarify how CO2–EOR projects that may transition to use of the CSA/ANSI ISO 27916:19 method during a reporting year will be required to report for the portion of the reporting year before they began using CSA/ANSI ISO 27916:19 and for the portion after they began using CSA/ANSI ISO 27916:19. Additional rationale for these amendments is available in the preamble to the 2023 Supplemental Proposal. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 AA. Subpart VV—Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916 We are finalizing several amendments to add subpart VV (Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916) to part 98 as proposed. Section III.Z.1. of this preamble discusses the final requirements of subpart VV. The EPA received several comments on the proposed subpart VV which are discussed in section III.V.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart VV as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart VV This section summarizes the substantive final amendments to subpart VV. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart VV can be found in this section. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal 2023 Supplemental Proposal. a. Source Category Definition In the 2022 Data Quality Improvements Proposal, the EPA proposed adding a new source category, subpart VV, to part 98 to add calculation and reporting requirements for quantifying geologic sequestration of CO2 in association with EOR operations, which would only apply to facilities that quantify the geologic sequestration of CO2 in association with EOR operations in conformance with the ISO standard designated as CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation and geological storage— Carbon dioxide storage using enhanced oil recovery.42 In our initial proposal, the EPA outlined the source category definition, rationale for no threshold, calculation methodology, and monitoring, recordkeeping, and reporting requirements. We noted at that time that under existing GHGRP requirements, facilities that receive CO2 for injection at EOR operations report under subpart UU (Injection of Carbon Dioxide), and facilities that geologically 42 Although the title of the standard references only EOR, Clause 1.1 of CSA/ANSI ISO 27916:19 indicates that the standard can apply to enhanced gas recovery as well. Therefore, any reference to EOR in subpart VV also applies to enhanced gas recovery. PO 00000 Frm 00065 Fmt 4701 Sfmt 4700 31865 sequester CO2 through EOR operations may instead opt-in to subpart RR (Geologic Sequestration of Carbon Dioxide). The EPA proposed to add new subpart VV to require reporting of incidental CO2 storage associated with EOR based on the CSA/ANSI ISO 27916:19 standard. We subsequently received detailed comments saying that the applicability of proposed subpart VV was unclear, specifically, proposed 40 CFR 98.480 ‘‘Definition of the Source Category.’’ The commenters were uncertain whether the EPA had intended to require facilities using CSA/ ANSI ISO 27916:19 to report under subpart VV or whether facilities that used CSA/ANSI ISO 27916:19 would have the option to choose under which subpart they would report to: subpart RR, subpart UU, or subpart VV. In the 2023 Supplemental Proposal, the EPA subsequently reproposed §§ 98.480 and 98.481 of subpart VV to clarify the applicability to each subpart. As explained in section III.P. of the preamble the 2023 Supplemental Proposal, the EPA clarified that if a facility elects to use the CSA/ANSI ISO 27916:19 method for quantifying geologic sequestration of CO2 in association with EOR operations, then the facility would be required under the GHGRP to report under new subpart VV (unless the facility chooses to report under subpart RR and has received an approved Monitoring, Reporting, and Verification Plan (MRV Plan) from EPA). The EPA further clarified that subpart VV is not intended to apply to facilities that use the content of CSA/ ANSI ISO 27916:19 for a purpose other than demonstrating secure geologic storage, such as only as a reference material or for informational purposes. Following review of subsequent comments received on the reproposed source category definition, we are finalizing the definition of the source category as proposed in the 2023 Supplemental Proposal. b. Reporting Threshold In the 2022 Data Quality Improvements Proposal, the EPA proposed no threshold for reporting under subpart VV (i.e., that subpart VV would be an ‘‘all-in’’ reporting subpart). The EPA also proposed under 40 CFR 98.480(c) that facilities subject only to subpart VV would not be required to report emissions under subpart C or any other subpart listed in 40 CFR 98.2(a)(1) or (2), consistent with the requirements for existing reporters under subpart UU. In the 2023 Supplemental Proposal, the EPA maintained no threshold is required for reporting, but amended the regulatory text to clarify that all CO2– E:\FR\FM\25APR2.SGM 25APR2 31866 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations EOR projects using CSA/ANSI ISO 27916:19 as a method of quantifying geologic sequestration that do not report under subpart RR would report under subpart VV. We also proposed text at 40 CFR 98.481(c) to clarify how CO2–EOR projects previously reporting under subpart UU that begin using CSA/ANSI ISO 27916:19 part-way through a reporting year must report. The EPA is finalizing these requirements as reproposed in the 2023 Supplemental Proposal. Additionally, we are finalizing revisions at 40 CFR 98.481(b) that facilities subject to subpart VV will not be subject to the off-ramp requirements of 40 CFR 98.2(i). Instead, once a facility opts-in to subpart VV, the owner or operator must continue for each year thereafter to comply with all requirements of the subpart, including the requirement to submit annual reports, until the facility demonstrates termination of the CO2–EOR project following the requirements of CSA/ ANSI ISO 27916:19. The operator must notify the Administrator of its intent to cease reporting and provide a copy of the CO2–EOR project termination documentation prepared for CSA/ANSI ISO 27916:19. lotter on DSK11XQN23PROD with RULES2 c. Calculation Methods In the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal, the EPA proposed incorporating the quantification methodology of CSA/ ANSI ISO 27916:19 for calculation of emissions. Under CSA/ANSI ISO 27916:19, the mass of CO2 stored is determined as the total mass of CO2 received minus the total mass of CO2 lost from project operations and the mass of CO2 lost from the EOR complex. The EOR complex is defined as the project reservoir, trap, and such additional surrounding volume in the subsurface as defined by the operator within which injected CO2 will remain in safe, long-term containment. Specific losses include those from leakage from production, handling, and recycling facilities; from infrastructure (including wellheads); from venting/flaring from production operations; and from entrainment within produced gas/oil/ water when this CO2 is not separated and reinjected. We are finalizing the calculation requirements as proposed. d. Monitoring, QA/QC, and Verification Requirements The EPA is finalizing as proposed the requirement for reporters to use the applicable monitoring and quality assurance requirements set forth in CSA/ANSI ISO 27916:19. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 e. Procedures for Estimating Missing Data The EPA is finalizing as proposed the requirement for reporters to use the applicable missing data and quality assurance procedures set forth in CSA/ ANSI ISO 27916:19. f. Data Reporting Requirements The EPA is finalizing, as proposed, that facilities will report the amount of CO2 stored, inputs included in the mass balance equation used to determine CO2 stored using the CSA/ANSI ISO 27916:19 methodology, and documentation providing the basis for that determination as set forth in CSA/ ANSI ISO 27916:19. Documentation includes providing the CSA/ANSI ISO 27916:19 EOR Operations Management Plan (OMP), which is required to specify: (1) a geological description of the site and the procedures for field management and operational containment during the quantification period; (2) the initial containment assurance plan to identify potential leakage pathways; (3) the plan for monitoring of potential leakage pathways; and (4) the monitoring methods for detecting and quantifying losses and how this will serve to provide the inputs into site-specific mass balance equations. Reporters must also specify any changes made to containment assurance and monitoring approaches and procedures in the EOR OMP made within the reporting year. We are also finalizing the reporting of the following information per CSA/ ANSI ISO 27916:19: (1) the quantity of CO2 stored during the year; (2) the formula and data used to quantify the storage, including the quantity of CO2 delivered to the CO2–EOR project and losses during the year; (3) the methods used to estimate missing data and the amounts estimated; (4) the approach and method for quantification utilized by the operator, including accuracy, precision and uncertainties; (5) a statement describing the nature of validation or verification, including the date of review, process, findings, and responsible person or entity; and (6) the source of each CO2 stream quantified as storage. The final rule also requires that reporters provide a copy of the independent engineer or geologist’s certification as part of reporting to subpart VV, if such a certification has been made. Finally, the EPA is finalizing a notification for project termination. The final rule specifies that the time for cessation of reporting under subpart VV is the same as under CSA/ANSI ISO 27916:19; the operator must notify the PO 00000 Frm 00066 Fmt 4701 Sfmt 4700 Administrator of its intent to cease reporting and provide a copy of the CO2–EOR project termination documentation. g. Records That Must Be Retained The EPA is finalizing as proposed the requirement that reporters meet the record retention requirements of 40 CFR 98.3(g) and the applicable recordkeeping retention requirements set forth in CSA/ANSI ISO 27916:19. 2. Summary of Comments and Responses on Subpart VV The EPA received several comments for subpart VV; the majority of these comments were received on the 2022 Data Quality Improvements Proposal and were previously addressed in the preamble to the 2023 Supplemental Proposal (see section III.P. of the preamble to the 2023 Supplemental Proposal). The EPA received only supportive comments on the proposed revisions to subpart VV in the 2023 Supplemental Proposal; see the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart VV. BB. Subpart WW —Coke Calciners We are finalizing the addition of subpart WW to part 98 (Coke Calciners) with revisions in some cases. Section III.BB.1. of this preamble discusses the final requirements of subpart WW. The EPA received several comments on the proposed subpart WW which are discussed in section III.BB.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart WW as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart WW This section summarizes the substantive final amendments to subpart WW. Major changes in this final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart WW can be found in this section. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations a. Source Category Definition The EPA is finalizing the source category definition as proposed, with one minor clarification. Specifically, we proposed that the coke calciner source category consists of process units that heat petroleum coke to high temperatures in the absence of air or oxygen for the purpose of removing impurities or volatile substances in the petroleum coke feedstock. Following review of comments received, the EPA is revising the source category definition from that proposed to remove the language ‘‘in the absence of air or oxygen.’’ See section III.BB.2. of this preamble for additional information on related comments and the EPA’s response. The final definition of the coke calciner source category includes, but is not limited to, rotary kilns or rotary hearth furnaces used to calcine petroleum coke and any afterburner or other equipment used to treat the process gas from the calciner. The source category includes all coke calciners, not just those co-located at petroleum refineries, to provide consistent requirements for all coke calciners. b. Reporting Threshold In the 2023 Supplemental Proposal, the EPA proposed no threshold for reporting under subpart WW. Because coke calciners are large emission sources, they are expected to emit over the 25,000 mtCO2e threshold generally required to report under existing GHGRP subparts with thresholds, and nearly all of them are also projected to exceed the 100,000 mtCO2e threshold. Therefore, the EPA projects that there are limited differences in the number of reporting facilities based on any of the emission thresholds considered. For this reason, the EPA is finalizing the coke calciner source category as an ‘‘all-in’’ subpart (i.e., regardless of their emissions profile). lotter on DSK11XQN23PROD with RULES2 c. Calculation Methods Coke calciners primarily emit CO2, but also have CH4 and N2O emissions as part of the process gas emission control combustion device operation. The EPA is finalizing, as proposed in the 2023 Supplemental Proposal, that CO2, CH4, and N2O emissions from each coke calcining unit be estimated. The EPA reviewed a number of different emissions estimation methods for coke calciners. We subsequently proposed, and are finalizing, to require either one of two separate calculation methods, the use of a CEMS or the carbon mass balance method for estimating emissions. Each of these VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 methodologies are used to estimate CO2 emissions. We are also finalizing, as proposed, that coke calciners also estimate process CH4 and N2O emissions based on the total CO2 emissions determined for the coke calciner and the ratio of the default CO2 emission factor for petroleum coke in table C–1 to subpart C of part 98 to the default CH4 and N2O emission factors for petroleum products in table C–2 to subpart C of part 98. Under the final methods, petroleum refineries with coke calciners are able to maintain their current calculation methods. Additional detail on the calculation methods reviewed are available in section IV.B. of the preamble to the 2023 Supplemental Proposal. Direct measurement using CEMS. The CEMS approach directly measures CO2 concentration and total exhaust gas flow rate for the combined process and combustion source emissions. CO2 mass emissions are calculated from these measured values using equation C–6 and, if necessary, equation C–7 in 40 CFR 98.33(a)(4). The EPA proposed that the CEMS method under subpart WW would be implemented consistent with subpart Y of part 98 (Petroleum Refineries), which required reporters to determine CO2 emissions from auxiliary fuel use discharged in the coke calciner exhaust stack using methods in subpart C of part 98, and to subtract those emissions from the measured CEMS emissions to determine the process CO2 emissions. We are finalizing this requirement. Carbon balance method. For those facilities that do not have a qualified CEMS in-place, facilities may use the carbon mass balance method, using data that is expected to be routinely monitored by coke calcining facilities. The carbon mass balance method uses the mass of green coke, calcined coke and petroleum coke dust removed from the dust collection system, along with the carbon content of the green and calcined coke, to estimate process CO2 emissions; the methodology is the same as current equation Y–13 of 40 CFR 98.253(g)(2) that is used for coke calcining processes co-located at petroleum refineries. d. Monitoring, QA/QC, and Verification Requirements The EPA is finalizing the monitoring methods to subpart WW as proposed. Direct measurement using CEMS. For direct measurement using CEMS, the CEMS method requires both a continuous CO2 concentration monitor and a continuous volumetric flow monitor. Reporters required to or electing to use CEMS must install, PO 00000 Frm 00067 Fmt 4701 Sfmt 4700 31867 operate, and calibrate the monitoring system according to subpart C (General Stationary Fuel Combustion Sources), which is consistent with the current requirements for coke calciner CO2 CEMS monitoring requirements within subpart Y. We are finalizing that all CO2 CEMS and flow rate monitors used for direct measurement of GHG emissions should comply with QA/QC procedures for daily calibration drift checks and quarterly or annual accuracy assessments, such as those provided in Appendix F to part 60 or similar QA/QC procedures. These requirements ensure the quality of the reported GHG emissions and are consistent with the current requirements for CEMS measurements within subparts A (General Provisions) and C of the GHGRP. Carbon balance method. The carbon mass balance method requires monitoring of mass quantities of green coke fed to the process, calcined coke leaving the process, and coke dust removed from the process by dust collection systems. It also requires periodic determination of carbon content of the green and calcined coke. For coke mass measurements, we are finalizing that the measurement device be calibrated according to the procedures specified by the updated NIST HB 44–2023: Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, 2023 edition (we have clarified the title and publication date of this method in the final rule) or the procedures specified by the manufacturer. We are requiring the measurement device be recalibrated either biennially or at the minimum frequency specified by the manufacturer. These requirements are to ensure the quality of the reported GHG emissions and to be consistent with the current requirements for coke calciner mass measurements within subpart Y. For carbon content of coke measurements, the owner or operator must follow approved analytical procedures and maintain and calibrate instruments used according to manufacturer’s instructions and to document the procedures used to ensure the accuracy of the measurement devices used. These requirements are to ensure the quality of the reported GHG emissions and to be consistent with the current requirements for coke calciner mass measurements within subpart Y. These determinations must be made monthly. If carbon content measurements are made more often than monthly, all measurements made within the calendar month must be used to determine the average for the month. E:\FR\FM\25APR2.SGM 25APR2 31868 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations e. Procedures for Estimating Missing Data The EPA is finalizing as proposed the procedures for estimating missing data. For the CEMS methodology, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations. For missing CEMS data, the missing data procedures in subpart C must be used. Under the carbon mass balance method, for each missing value of mass or carbon content of coke, reporters must use the average of the data measurements before and after the missing data period. If, for a particular parameter, no quality assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. Similarly, if no quality-assured data are available after the missing data incident, the substitute data value must be the most recently acquired quality-assured value obtained prior to the missing data period. f. Data Reporting Requirements The EPA is finalizing the data reporting requirements of subpart WW as proposed. For coke calcining units, the owner and operator shall report the coke calciner unit ID number and maximum rated throughput of the unit, the method used to calculate GHG emissions, and the calculated CO2, CH4, and N2O annual emissions for each unit, expressed in metric tons of each pollutant emitted. We are also requiring the owner and operator to report the annual mass of green coke fed to the coke calcining unit, the annual mass of marketable petroleum coke produced by the coke calcining unit, the annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit, the annual average mass fraction carbon content of green coke fed to the unit, and the annual average mass fraction carbon content of the marketable petroleum coke produced by the coke calcining unit. lotter on DSK11XQN23PROD with RULES2 g. Records That Must Be Retained The EPA is finalizing the record retention requirements of subpart WW as proposed. Facilities are required to maintain records documenting the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. For the coke calciners source category, we are finalizing that the verification software specified in 40 CFR 98.5(b) be used to fulfill the recordkeeping requirements for the following five data elements: • Monthly mass of green coke fed to the coke calcining unit; • Monthly mass of marketable petroleum coke produced by the coke calcining unit; • Monthly mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit; • Average monthly mass fraction carbon content of green coke fed to the coke calcining unit; and • Average monthly mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit. 2. Summary of Comments and Responses on Subpart WW This section summarizes the major comments and responses related to the proposed subpart WW. The EPA previously requested comment on the addition of coke calciners production source category as a new subpart to part 98 in the 2022 Data Quality Improvements Proposal. The EPA received several comments for subpart WW on the 2022 Data Quality Improvements Proposal; many of these comments were previously addressed in the preamble to the 2023 Supplemental Proposal, wherein the EPA proposed to add new subpart WW for coke calciners (see section IV.B. of the preamble to the 2023 Supplemental Proposal). The EPA received additional comments regarding the proposed subpart WW following the 2023 Supplemental Proposal. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart WW. Comment: One commenter stated that the description of coke calciners may be overly narrow. The commenter contended that the language ‘‘in the absence of air or oxygen’’ is not necessarily accurate. The commenter stated that air/oxygen is necessary for combustion to occur, and that the high temperatures required for proper PO 00000 Frm 00068 Fmt 4701 Sfmt 4700 calcination are from the combustion of volatiles and carbon in the green coke. Response: We understand that air is introduced in the coke calciner to burn the volatiles from the coke, but the air is introduced in a limited fashion (limited oxygen) so that the complete combustion of coke in the calciner does not occur. However, we agree with the commenter that the phrase ‘‘in the absence of air or oxygen’’ may be too restrictive and we have deleted this phrase from the proposed source category description at 40 CFR 98.490(a) in the final rule. Comment: One commenter stated that coke calciners that use refinery fuel gas or natural gas during startup or during hot standby should be allowed to report emissions from these fuel gases using a methodology from subpart C of part 98, separately from the coke calciner emissions. The commenter stated that where coke calcining and fuel gas combustion are occurring simultaneously, the fuel gas emissions should be subtracted from the emissions that are calculated using CEMS and the proposed stack flow methodology to avoid double counting. The commenter added that the requirements for fuel gas or natural gas composition and heat content use in coke calciners should be the same as required in subpart C. Response: We agree with the commenter and the issues identified by the commenter were addressed in the 2023 Supplemental Proposal. We are finalizing these provisions for treating GHG emissions from auxiliary fuel use as proposed (see 40 CFR 98.493(b)(1)). CC. Subpart XX—Calcium Carbide Production We are finalizing the addition of subpart XX (Calcium Carbide Production) to part 98 as proposed. Section III.CC.1. of this preamble discusses the final requirements of subpart XX. The EPA received comments on the proposed subpart XX which are discussed in section III.CC.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the addition of subpart XX as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart XX This section summarizes the final amendments to subpart XX. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart XX can be found in this section and section III.CC.2. of this preamble. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Source Category Definition The EPA is finalizing the source category definition as proposed. We are defining calcium carbide production to include any process that produces calcium carbide. Calcium carbide is an industrial chemical manufactured from lime (CaO) and carbon, usually petroleum coke, by heating the mixture to 2,000 to 2,100 C (3,632 to 3,812 °F) in an electric arc furnace. During the production of calcium carbide, the use of carbon-containing raw materials (petroleum coke) results in emissions of CO2. Although we considered accounting for emissions from the production of acetylene at calcium carbide facilities in the 2022 Data Quality Improvements Proposal, we ultimately determined that acetylene is not produced at the one known plant that produces calcium carbide. For this reason, in the 2023 Supplemental Proposal we did not propose, and as such are not taking final action on, inclusion of reporting of CO2 emissions from the production of acetylene from calcium carbide under subpart XX. lotter on DSK11XQN23PROD with RULES2 b. Reporting Threshold In the 2023 Supplemental Proposal, the EPA proposed no threshold for reporting under subpart XX. The current estimate of emissions from the single known calcium carbide production facility in the United States exceeds 25,000 mtCO2e by a factor of about 1.9. Therefore we are finalizing, as proposed, the calcium carbide source category as an ‘‘all-in’’ subpart. For a full discussion of the threshold analysis, please refer to section IV.C. of the preamble to the 2023 Supplemental Proposal. c. Calculation Methods In the 2023 Supplemental Proposal, the EPA reviewed the production processes and available emissions estimation methods for calcium carbide production including a default emission factor methodology, a carbon balance methodology (IPCC Tier 3), and direct measurement using CEMS (see section IV.C.5. of the preamble to the 2023 Supplemental Proposal). We subsequently proposed and are finalizing two different methods for quantifying GHG emissions from calcium carbide manufacturing, depending on current emissions monitoring at the facility. If a qualified VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 CEMS is in place, the CEMS must be used. Otherwise, the facility can elect to either install a CEMS or elect to use the carbon mass balance method. Direct measurement using CEMS. Facilities with an existing CEMS that meet the requirements outlined in subpart C of part 98 (General Stationary Fuel Combustion) are required to use CEMS to estimate combined process and combustion CO2 emissions. Facilities are required to follow the requirements of subpart C to estimate all CO2 emissions from the industrial source. Facilities will be required to follow subpart C to estimate emissions of CO2, CH4, and N2O from stationary combustion. Carbon balance method. For facilities that do not have CEMS that meet the requirements of 40 CFR part 98 subpart C, the alternate monitoring method is the carbon balance method. For any stationary combustion units included at the facility, facilities will be required to follow the existing requirements at 40 CFR part 98, subpart C to estimate emissions of CO2, CH4, and N2O from stationary combustion. Use of facility specific information is consistent with IPCC Tier 3 methods and is the preferred method for estimating emissions for other GHGRP sectors. d. Monitoring, QA/QC, and Verification requirements The EPA is finalizing the monitoring, QA/QC, and verification requirements to subpart XX as proposed. We are finalizing two separate monitoring methods: direct measurement and a mass balance emission calculation. Direct measurement using CEMS. For facilities where process emissions and/ or combustion GHG emissions are contained within a stack or vent, facilities can take direct measurement of the GHG concentration in the stack gas and the flow rate of the stack gas using a CEMS. Under the final rule, if facilities use an existing CEMS to meet the monitoring requirements, they are required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions, facilities will be required to follow the requirements of subpart C to estimate emissions. The CEMS method requires both a continuous CO2 concentration monitor and a continuous volumetric flow monitor. To qualify as a CEMS, the monitors are required to be installed, operated, and calibrated according to subpart C of part 98 (40 CFR 98.33(a)(4)), which is consistent with CEMS requirements in other GHGRP subparts. PO 00000 Frm 00069 Fmt 4701 Sfmt 4700 31869 Carbon balance method. For facilities using the carbon mass balance method, we are requiring the facility to determine the annual mass for each material used for the calculations of annual process CO2 emissions by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating information. For the carbon content of the materials used to calculate process CO2 emissions, we are finalizing a requirement that the owner or operator determine the carbon content using material supplier information or collect and analyze at least three representative samples of the material inputs and outputs each year. The final rule will require the carbon content be analyzed at least annually using standard ASTM methods, including their QA/QC procedures. To reduce burden, if a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, the reporter does not have to determine the monthly mass or annual carbon content of that input or output. e. Procedures for Estimating Missing Data We are finalizing as proposed the use of substitute data whenever a qualityassured value of a parameter is used to calculate emissions is unavailable, or ‘‘missing.’’ If the carbon content analysis of carbon inputs or outputs is missing, the substitute data value will be based on collected and analyzed representative samples for average carbon contents. If the monthly mass of carbon-containing inputs and outputs is missing, the substitute data value will be based on the best available estimate of the mass of the inputs and outputs from all available process data or data used for accounting purposes, such as purchase records. The likelihood for missing process input or output data is low, as businesses closely track their purchase of production inputs. These missing data procedures are the same as those for the ferroalloy production source category, subpart K of part 98, under which the existing U.S. calcium carbide production facility currently reports. f. Data Reporting Requirements The EPA is finalizing, as proposed, that each carbon carbide production facility report the annual CO2 emissions E:\FR\FM\25APR2.SGM 25APR2 31870 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 from each calcium carbide production process, as well as any stationary fuel combustion emissions. In addition, we are finalizing requirements for facilities to provide additional information that forms the basis of the emissions estimates, along with supplemental data, so that we can understand and verify the reported emissions. All calcium carbide production facilities will be required to report their annual production and production capacity, total number of calcium carbide production process units, annual consumption of petroleum coke, each end use of any calcium carbide produced and sent off site, and, if the facility produces acetylene, the annual production of acetylene, the quantity of calcium carbide used for acetylene production at the facility, and the end use of the acetylene produced on-site. The EPA is also finalizing reporting the end use of calcium carbide sent off site, as well as acetylene production information for current or future calcium carbide production facilities, to inform future Agency policy under the CAA. As proposed, we are finalizing requirements that if a facility uses CEMS to measure their CO2 emissions, they will be required to also report the identification number of each process unit; the EPA is clarifying in the final rule that if a facility uses CEMS, emissions are reported from each CEMS monitoring location. If a CEMS is not used to measure CO2 emissions, the facility will also report the method used to determine the carbon content of each material for each process unit, how missing data were determined, and the number of months missing data procedures were used. g. Records That Must Be Retained The EPA is finalizing as proposed the requirement that facilities maintain records of information used to determine the reported GHG emissions, to allow us to verify that GHG emissions monitoring and calculations were done correctly. If a facility uses a CEMS to measure their CO2 emissions, they will be required to record the monthly calcium carbide production from each process unit and the number of monthly and annual operating hours for each process unit. If a CEMS is not used, the facility will be required to retain records of monthly production, monthly and annual operating hours, monthly quantities of each material consumed or produced, and carbon content determinations. As proposed, we are finalizing requirements that the owner or operator maintain records of how measurements VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 are made, including measurements of quantities of materials used or produced and the carbon content of process input and output materials. The procedures for ensuring accuracy of measurement methods, including calibration, must be recorded. The final rule also requires the retention of a record of the file generated by the verification software specified in 40 CFR 98.5(b) including: • Carbon content (percent by weight expressed as a decimal fraction) of the reducing agent (petroleum coke), carbon electrode, product produced, and nonproduct outgoing materials; and • Annual mass (tons) of the reducing agent (petroleum coke), carbon electrode, product produced, and nonproduct outgoing materials. 2. Summary of Comments and Responses on Subpart XX The EPA previously requested comment on the addition of a calcium carbide source category as a new subpart to part 98 in the 2022 Data Quality Improvements Proposal. The EPA received one comment objecting to the addition of the proposed source category and one comment on the potential calculation methodology. Subsequently, the EPA responded to the comments and proposed to add new subpart XX for calcium carbide (see section IV.C. of the preamble to the 2023 Supplemental Proposal). The EPA received no comments regarding proposed subpart XX following the 2023 Supplemental Proposal. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart XX. DD. Subpart YY—Caprolactam, Glyoxal, and Glyoxylic Acid Production We are finalizing the addition of subpart YY (Caprolactam, Glyoxal, and Glyoxylic Acid Production) to part 98 with revisions in some cases. Section III.DD.1. of this preamble discusses the final requirements of subpart YY. Major comments, as applicable, are addressed in section III.DD.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the revisions to subpart YY as described in section VI. of this preamble. PO 00000 Frm 00070 Fmt 4701 Sfmt 4700 1. Summary of Final Amendments to Subpart YY This section summarizes the substantive final amendments to subpart YY. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart YY can be found in this section. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Source Category Definition In the 2023 Supplemental Proposal, the EPA proposed that the caprolactam, glyoxal, or glyoxylic acid source category, as defined under subpart YY, would include any facility that produces caprolactam, glyoxal, or glyoxylic acid. Caprolactam is a crystalline solid organic compound with a wide variety of uses, including brush bristles, textile stiffeners, film coatings, synthetic leather, plastics, plasticizers, paint vehicles, cross-linking for polyurethanes, and in the synthesis of lysine. Caprolactam is primarily used in the manufacture of synthetic fibers, especially Nylon 6. Glyoxal is a solid organic compound with a wide variety of uses, including as a crosslinking agent in various polymers for paper coatings, textile finishes, adhesives, leather tanning, cosmetics, and oil-drilling fluids; as a sulfur scavenger in natural gas sweetening processes; as a biocide in water treatment; to improve moisture resistance in wood treatment; and as a chemical intermediate in the production of pharmaceuticals, dyestuffs, glyoxylic acid, and other chemicals. It is also used as a less toxic substitute for formaldehyde in some applications (e.g., in wood adhesives and embalming fluids). Glyoxylic acid is a solid organic compound exclusively produced by the oxidation of glyoxal with nitric acid. It is used mainly in the synthesis of vanillin, allantoin, and several antibiotics like amoxicillin, ampicillin, and the fungicide azoxystrobin. We are finalizing the source category definition to include any facility that produces caprolactam, glyoxal, or glyoxylic acid as proposed. The source category will exclude the production of glyoxal through the LaPorte process (i.e., the gas-phase catalytic oxidation of ethylene glycol with air in the presence of a silver or copper catalyst). As explained in the 2023 Supplemental Proposal, the LaPorte process does not E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations emit N2O and there are no methods for estimating CO2 in available literature. lotter on DSK11XQN23PROD with RULES2 b. Reporting Threshold In the 2023 Supplemental Proposal, the EPA proposed no threshold for reporting under subpart YY (i.e., that subpart YY would be an ‘‘all-in’’ reporting subpart). The EPA noted that the total process emissions from current production of caprolactam, glyoxal, and glyoxylic acid are estimated at 1.2 million mtCO2e, largely from two known caprolactam production facilities; although the known universe of facilities that produce caprolactam, glyoxal, and glyoxylic acid in the United States is four to six total facilities. We proposed that adding caprolactam, glyoxal, and glyoxylic acid production as an ‘‘all-in’’ subpart (i.e., regardless of the facility emissions profile) is a conservative approach to gather information from as many facilities that produce caprolactam, glyoxal, and glyoxylic acid as possible, especially if production of glyoxal and glyoxylic acid increase in the near future. The EPA is finalizing these requirements as proposed. c. Calculation Methods In the 2023 Supplemental Proposal, the EPA reviewed the production processes and available emissions estimation methods for caprolactam, glyoxal, and glyoxylic acid production and proposed that only N2O emissions would be estimated from these processes. The EPA also proposed to require the reporting of combustion emissions from facilities that produce caprolactam, glyoxal, and glyoxylic acid, including CO2, CH4, and N2O. The EPA reviewed two methods from the 2006 IPCC Guidelines,43 including the Tier 2 and Tier 3 methodologies, for calculating N2O emissions from the production of caprolactam, glyoxal, and glyoxylic acid, and subsequently proposed the IPCC Tier 2 approach to quantify N2O process emissions. We are finalizing the N2O calculation requirements as proposed, with minor revisions. Following the Tier 2 approach established by the IPCC, reporters will apply default N2O generation factors on a site-specific basis. This requires raw material input to be known in addition to a standard N2O generation factor, which differs for each of the three chemicals. In addition, Tier 2 requires site-specific knowledge of the use of 43 IPCC 2006. IPCC Guidelines for National Greenhouse Gas Inventories, Volume 3, Industrial Processes and Product Use. Chapter 3, Chemical Industry Emissions. 2006. www.ipccnggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_ 3_Ch3_Chemical_Industry.pdf. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 N2O control technologies. The volume or mass of each product is measured with a flow meter or weigh scales. The process-related N2O emissions are estimated by multiplying the generation factor by the production and the destruction efficiency of any N2O control technology. The EPA is revising the final rule to adjust the N2O generation factors (proposed in table 1 to subpart YY) for glyoxal and glyoxylic acid production to correctly reflect the conversion of the IPCC default emission factors, which were intended to be converted from metric tons N2O emitted per metric ton of product produced to kg N2O per metric ton of product produced using a conversion factor of 1,000 kg per metric ton. The final rule corrects the generation factor for glyoxal from 5,200 to 520 and, for glyoxylic acid, from 1,000 to 100. The EPA is finalizing a minor clarification to equation 1 to 40 CFR 98.513(d)(2) (proposed as equation YY–1) to re-order the defined parameters of the equation to follow their order of appearance in the equation. The EPA is also finalizing an additional equation (equation 3 to 40 CFR 98.513(f)) from the proposed rule, which sums the monthly process emissions estimated by equation 2 to 40 CFR 98.513(e) (proposed as equation YY–2) to an annual value. This additional equation clarifies the methodology for reporting annual emissions and does not require the collection of any additional data. For any stationary combustion units included at the facility, we proposed that facilities would be required to follow the existing requirements in 40 CFR part 98, subpart C to calculate emissions of CO2, CH4 and N2O from stationary combustion. We are finalizing the combustion calculation requirements as proposed. d. Monitoring, QA/QC, and Verification Requirements Monitoring is required to comply with the N2O calculation methodologies for reporters that produce caprolactam, glyoxal, and glyoxylic acid. In the 2023 Supplemental Proposal, the EPA proposed that reporters that produce caprolactam, glyoxal, and glyoxylic acid are to determine the monthly and annual production quantities of each chemical and to determine the N2O destruction efficiency of any N2O abatement technologies in use. The EPA is finalizing as proposed the requirement for reporters to either perform direct measurement of production quantities or to use existing plant procedures to determine production quantities. E.g., the production rate can be determined PO 00000 Frm 00071 Fmt 4701 Sfmt 4700 31871 through sales records or by direct measurement using flow meters or weigh scales. For determination of the N2O destruction efficiency, we are finalizing as proposed the requirement that reporters estimate the destruction efficiency for each N2O abatement technology. The destruction efficiency can be determined by using the manufacturer’s specific destruction efficiency or estimating the destruction efficiency through process knowledge. Documentation of how process knowledge was used to estimate the destruction efficiency is required. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided that the results are still relevant to the current vent stream conditions. For the caprolactam, glyoxal, and glyoxylic acid production subpart, we are requiring reporters to perform all applicable flow meter calibration and accuracy requirements and maintain documentation as specified in 40 CFR 98.3(i). e. Procedures for Estimating Missing Data For caprolactam, glyoxal, and glyoxylic acid production, the EPA is finalizing as proposed the requirement that substitute data for each missing production value is the best available estimate based on all available process data or data used for accounting purposes (such as sales records). For the control device destruction efficiency, assuming that the control device operation is generally consistent from year to year, the substitute data value should be the most recent quality assured value. f. Data Reporting Requirements The EPA is finalizing, as proposed, that facilities must report annual N2O emissions (in metric tons) from each production line. In addition, facilities must submit the following data to facilitate understanding of the emissions data and verify the reasonableness of the reported emissions: number of process lines; annual production capacity; annual production; number of operating hours in the calendar year for each process line; abatement technology used and installation dates (if applicable); abatement utilization factor for each process line; number of times in the reporting year that missing data procedures were followed to measure production quantities of caprolactam, glyoxal, or glyoxylic acid (months); and E:\FR\FM\25APR2.SGM 25APR2 31872 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations overall percent N2O reduction for each chemical for all process lines. lotter on DSK11XQN23PROD with RULES2 g. Records That Must Be Retained The EPA is finalizing as proposed the requirement that facilities maintain records documenting the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. We are also requiring, as proposed, that facilities maintain records documenting the estimate of production rate and abatement technology destruction efficiency through accounting procedures and process knowledge, respectively. Finally, the EPA is also requiring, as proposed, the retention of a record of the file generated by the verification software specified in 40 CFR 98.5(b) including: • Monthly production quantities of caprolactam from all process lines; • Monthly production quantities of glyoxal from all process lines; and • Monthly production quantities of glyoxylic acid from all process lines. We are revising the final rule to clarify that these monthly production quantities must be supplied in metric tons and for each process line. Additionally, we are adding a requirement that facilities maintain records of the destruction efficiency of the N2O abatement technology from each process line, consistent with requirements of equation 2 to 40 CFR 98.513(e). Facilities will enter this information into EPA’s electronic verification software in order to ensure proper verification of the reported emission values. Following electronic verification, facilities will be required to retain a record of the file generated by the verification software specified in 40 CFR 98.5(b), therefore, no additional burden is anticipated. 2. Summary of Comments and Responses on Subpart YY The EPA previously requested comment on the addition of a caprolactam, glyoxal, and glyoxylic acid production source category as a new subpart to part 98 in the 2022 Data Quality Improvements Proposal. The EPA received no comments regarding the addition of the proposed source category. Subsequently, the EPA proposed to add new subpart YY for caprolactam, glyoxal, and glyoxylic acid production (see section IV.D. of the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 preamble to the 2023 Supplemental Proposal). The EPA received no comments regarding proposed subpart YY following the 2023 Supplemental Proposal. EE. Subpart ZZ—Ceramics Manufacturing We are finalizing the addition of subpart ZZ of part 98 (Ceramics Manufacturing) with revisions in some cases. Section III.EE.1. of this preamble discusses the final requirements of subpart ZZ. The EPA received a number of comments on the proposed subpart ZZ which are discussed in section III.EE.2. of this preamble. We are also finalizing as proposed related confidentiality determinations for data elements resulting from the addition of subpart ZZ as described in section VI. of this preamble. 1. Summary of Final Amendments to Subpart ZZ This section summarizes the final amendments to subpart ZZ. Major changes to the final rule as compared to the proposed revisions are identified in this section. The rationale for these and any other changes to 40 CFR part 98, subpart ZZ can be found in section III.EE.2. of this preamble. Additional rationale for these amendments is available in the preamble to the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal. a. Source Category Definition In the 2023 Supplemental Proposal, the EPA defined the ceramics manufacturing source category as any facility that uses nonmetallic, inorganic materials, many of which are claybased, to produce ceramic products such as bricks and roof tiles, wall and floor tiles, table and ornamental ware (household ceramics), sanitary ware, refractory products, vitrified clay pipes, expanded clay products, inorganic bonded abrasives, and technical ceramics (e.g., aerospace, automotive, electronic, or biomedical applications). The EPA also proposed that the ceramics source category would apply to facilities that annually consume at least 2,000 tons of carbonates or 20,000 tons of clay heated to a temperature sufficient to allow the calcination reaction to occur, and operate a ceramics manufacturing process unit. The proposed definition of ceramics manufacturers as facilities that use at least the minimum quantity of carbonates or clay (2,000 tons/20,000 tons) was considered consistent with subpart U of part 98 (Miscellaneous Uses of Carbonate). This minimum 2,000 tons of carbonate use was added PO 00000 Frm 00072 Fmt 4701 Sfmt 4700 to subpart U in the 2009 Final Rule based on comments received on the April 10, 2009 proposed rule (74 FR 16448), where commenters requested a carbonate use threshold of 2,000 tons in order to exempt small operations and activities which use carbonates in trace quantities. The proposed source category definition for ceramics manufacturing in the 2023 Supplemental Proposal established a minimum production level as a means to exclude and thus reduce the reporting burden for small artisan-level ceramics manufacturing processes. We defined a ceramics manufacturing process unit as a kiln, dryer, or oven used to calcine clay or other carbonate-based materials for the production of a ceramics product. The EPA is finalizing the definition of the source category with one change. We are revising the minimum production level in the definition from ‘‘at least 2,000 tons of carbonates or 20,000 tons of clay which is heated to a temperature sufficient to allow the calcination reaction to occur’’ to ‘‘at least 2,000 tons of carbonates, either as raw materials or as a constituent in clay, which is heated to a temperature sufficient to allow the calcination reaction to occur.’’ These final revisions focus the production level on the carbonates contained within the raw material rather than the total tons of clay; the final revisions will provide a more accurate means of assessing applicability. Facilities will be required to estimate their carbonate usage using available records to determine applicability. For example, facilities that use clay as a raw material input could calculate whether they meet the carbonate use threshold by multiplying the amount of clay they consume (and heat to calcination) annually by the weight fraction of carbonates contained in the clay. These final revisions add two harmonizing edits to 40 CFR 98.523(b)(1) and 98.526(c)(2) to clarify that the carbonate-based raw materials include clay. b. Reporting Threshold In the 2023 Supplemental Proposal, the EPA proposed that facilities must report under subpart ZZ if they met the definition of the source category and if their estimated combined emissions (including from stationary combustion and all applicable source categories) exceed a 25,000 mtCO2e threshold. We are finalizing the threshold as proposed. The final definition of ceramics manufacturers as facilities that use at least the minimum quantity of carbonates (2,000 tons, either as raw materials or as a constituent in clay) and E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 the 25,000 mtCO2e threshold are both expected to ensure that small ceramics manufacturers are excluded. It is estimated that over 25 facilities will meet the definition of a ceramics manufacturer and the threshold of 25,000 mtCO2e for reporting. For a full discussion of this analysis, section IV.E. of the preamble to the 2023 Supplemental Proposal. c. Calculation Methods In the 2023 Supplemental Proposal, the EPA reviewed the production processes and available emissions estimation methods for ceramics manufacturing and proposed that only CO2 emissions would be estimated from these processes. The EPA also proposed to require the reporting of combustion emissions, including CO2, CH4, and N2O from the ceramics manufacturing unit and other combustion sources on site. In the 2023 Supplemental Proposal, the EPA reviewed the production processes and available emissions estimation methods for ceramics manufacturing including a basic mass balance methodology that assumed a fixed percentage for carbonates consumed (IPCC Tier 1), a carbon balance methodology (IPCC Tier 3) based on carbon content and the mass of materials input, and direct measurement using CEMS (see section IV.C.5. of the preamble to the 2023 Supplemental Proposal). We are finalizing, as proposed, two different methods for quantifying GHG emissions from ceramics manufacturing, depending on current emissions monitoring at the facility. If a qualified CEMS is in place, the CEMS must be used. Otherwise, the facility can elect to either install a CEMS or elect to use the carbon mass balance method. Direct measurement using CEMS. Facilities with a CEMS that meet the requirements in subpart C of part 98 (General Stationary Fuel Combustion) will be required to use CEMS to estimate the combined process and combustion CO2 emissions. The CEMS measures CO2 concentration and total exhaust gas flow rate for the combined process and combustion source emissions. CO2 mass emissions will be calculated from these measured values using equation C–6 and, if necessary, equation C–7 in 40 CFR 98.33(a)(4). The combined process and combustion CO2 emissions will be calculated according to the Tier 4 Calculation Methodology specified in 40 CFR 98.33(a)(4). Facilities will be required to use subpart C to estimate emissions of CO2, CH4, and N2O from stationary combustion. Carbon balance method. For facilities using carbon mass balance method, the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 carbon content and the mass of carbonaceous materials input to the process must be determined. The facility must measure the consumption of specific process inputs and the amounts of these materials consumed by end-use/product type. Carbon contents of materials must be determined through the analysis of samples of the material or from information provided by the material suppliers. Additionally, the quantities of materials consumed and produced during production must be measured and recorded. CO2 emissions are estimated by multiplying the carbon content of each raw material by the corresponding mass, by a carbonate emission factor, and by the decimal fraction of calcination achieved for that raw material. We are finalizing the carbonate emission factors provided in table 1 to subpart ZZ of part 98 as proposed. These factors, pulled from table N–1 to subpart N of part 98, and from Table 2.1 of the 2006 IPCC Guidelines,44 are based on stoichiometric ratios and represent the weighted average of the emission factors for each particular carbonate. Emission factors provided by the carbonate vendor for other minerals not listed in table 1 to subpart ZZ may also be used. For any stationary combustion units included at the facility, facilities will be required to follow subpart C to estimate emissions of CO2, CH4, and N2O from stationary combustion. Use of facility specific information under the carbon mass balance method is consistent with IPCC Tier 3 methods and is the preferred method for estimating emissions for other GHGRP sectors. d. Monitoring, QA/QC, and Verification Requirements The EPA is finalizing, as proposed, two separate monitoring methods: direct measurement and a mass balance emission calculation. Direct measurement using CEMS. We are finalizing the CEMS monitoring requirements as proposed. In the case of ceramics manufacturing, process and combustion GHG emissions from ceramics process units are typically emitted from the same stack. If facilities use an existing CEMS to meet the monitoring requirements, they will be required to use CEMS to estimate CO2 emissions. Where the CEMS capture all combustion- and process-related CO2 emissions, facilities will be required to follow the requirements of subpart C of part 98 to estimate all CO2 emissions 44 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 3, Industrial Processes and Product Use, Mineral Industry Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/ pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf. PO 00000 Frm 00073 Fmt 4701 Sfmt 4700 31873 from the industrial source. The CEMS method requires both a continuous CO2 concentration monitor and a continuous volumetric flow monitor. To qualify as a CEMS, the monitors will be required to be installed, operated, and calibrated according to subpart C of part 98 (40 CFR 98.33(a)(4)), which is consistent with CEMS requirements in other GHGRP subparts. Carbon balance method. We are finalizing the carbon mass balance method as proposed, with one change. The carbon mass balance method requires monitoring of mass quantities of carbonate-based raw material (e.g., clay) fed to the process, establishing the mass fraction of carbonate-based minerals in the raw material, and an emission factor based on the type of carbonate consumed. The mass quantities of carbonate-based raw materials consumed by each ceramics process unit can be determined using direct weight measurement of plant instruments or techniques used for accounting purposes, such as calibrated scales, weigh hoppers, or weigh belt feeders. The direct weight measurement can then be compared to records of raw material purchases for the year. For the carbon content of the materials used to calculate process CO2 emissions, the final rule requires that the owner or operator determine the carbon mass fraction either by using information provided by the raw material supplier, by collecting and sending representative samples of each carbonate-based material consumed to an off-site laboratory for a chemical analysis of the carbonate content (weight fraction), or by choosing to use the default value of 1.0. The use of 1.0 for the mass fraction assumes that the carbonate-based raw material comprises 100 percent of one carbonate-based mineral. We are revising the final rule to also state that where it is determined that the mass fraction of a carbonatebased raw material is below the detection limit of available testing standards, the facility must assume a default of 0.005 for that material. We are revising the final rule to allow facilities that determine the carbonatebased mineral mass fractions of a carbonate-based material to use additional sampling and chemical analysis methods to provide additional flexibility for facilities. Specifically, we are revising 40 CFR 98.524(b) from requiring sampling and chemical analysis using consensus standards that specify x-ray fluorescence to requiring that facilities use an ‘‘x-ray fluorescence test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards E:\FR\FM\25APR2.SGM 25APR2 31874 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 organization’’ (e.g., ASTM, American Society of Mechanical Engineers (ASME), American Petroleum Institute (API)). The final rule requires the carbon content be analyzed at least annually to verify the mass fraction data provided by the supplier of the raw material. For the ceramics manufacturing source category, we are finalizing the QA/QC requirements as proposed. Reporters must calibrate all meters or monitors and maintain documentation of this calibration as documented in subpart A of part 98 (General Provisions). These meters or monitors should be calibrated prior to the first reporting year, using a suitable method published by a consensus standards organization, and will be required to be recalibrated either annually or at the minimum frequency specified by the manufacturer. In addition, any flow rate monitors used for direct measurement will be required to comply with QA/QC procedures for daily calibration drift checks and quarterly or annual accuracy assessments, such as those provided in Appendix F to part 60 or similar QA/QC procedures. We are finalizing these requirements to ensure the quality of the reported GHG emissions and to be consistent with the current requirements for CEMS measurements within subparts A (General Provisions) and C of the GHGRP. For measurements of carbonate content, reporters will assess representativeness of the carbonate content received from suppliers with laboratory analysis. e. Procedures for Estimating Missing Data We are finalizing the procedures for estimation of missing data as proposed. The final rule requires the use of substitute data whenever a qualityassured value of a parameter that is used to calculate emissions is unavailable, or ‘‘missing.’’ For example, if the CEMS malfunctions during unit operation, the substitute data value would be the average of the quality-assured values of the parameter immediately before and immediately after the missing data period. For missing data on the amounts of carbonate-based raw materials consumed, we are finalizing that reporters must use the best available estimate based on all available process data or data used for accounting purposes, such as purchase records. For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials, reporters will assume that the mass fraction of each carbonate-based mineral is 1.0. The use of 1.0 for the mass fraction assumes that the carbonate-based raw material comprises 100 percent of one carbonate- VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 based mineral. Missing data procedures will be applicable for CEMS measurements, mass measurements of raw material, and carbon content measurements. f. Data Reporting Requirements The EPA is finalizing the data reporting requirements for subpart ZZ as proposed, with one minor revision. Each ceramics manufacturing facility must report the annual CO2 process emissions from each ceramics manufacturing process, as well as any stationary fuel combustion emissions. In addition, facilities must report additional information that forms the basis of the emissions estimates so that we can understand and verify the reported emissions. For ceramic manufacturers, the additional information will include: the total number of ceramics process units at the facility and the total number of units operating; annual production of each ceramics product for each process unit and for all ceramics process units combined; the annual production capacity of each ceramics process unit; and the annual quantity of carbonatebased raw material charged to each ceramics process unit and for all ceramics process units combined. The EPA has revised the final rule to clarify at 40 CFR 98.526(c) that facilities that use the carbon balance method must also report the annual quantity of each carbonate-based raw material (including clay) charged to each ceramics process unit. This change is consistent with the requirements the EPA proposed for facilities conducting direct measurement using CEMS, and is not anticipated to substantively impact the burden to reporters as proposed. For ceramic manufacturers with non-CEMS units, the finalized rules will also require reporting of the following information: the method used for the determination for each carbon-based mineral in each raw material; applicable test results used to verify the carbonate based mineral mass fraction for each carbonate-based raw material charged to a ceramics process unit, including the date of test and test methods used; and the number of times in the reporting year that missing data procedures were used. g. Records That Must Be Retained The EPA is finalizing the record retention requirements of subpart ZZ as proposed. All facilities are required to maintain monthly records of the ceramics manufacturing rate for each ceramics process unit and the monthly amount of each carbonate-based raw PO 00000 Frm 00074 Fmt 4701 Sfmt 4700 material charged to each ceramics process unit. For facilities that use the carbon balance procedure, the final rule requires facilities to also maintain monthly records of the carbonate-based mineral mass fraction for each mineral in each carbonate-based raw material. Additionally, facilities that use the carbon balance procedure will be required to maintain (1) records of the supplier-provided mineral mass fractions for all raw materials consumed annually; (2) results of all analyses used to verify the mineral mass fraction for each raw material (including the mass fraction of each sample, the date of test, test methods and method variations, equipment calibration data, and identifying information for the laboratory conducting the test); and (3) annual operating hours for each unit. If facilities use the CEMS procedure, they are required to maintain the CEMS measurement records. Procedures for ensuring accuracy of measurement methods, including calibration, must be recorded. The final rule requires records of how measurements are made, including measurements of quantities of materials used or produced and the carbon content of minerals in raw materials. Finally, the final rule requires the retention of a record of the file generated by the verification software specified in 40 CFR 98.5(b) including: • Annual average decimal mass fraction of each carbonate-based mineral per carbonate-based raw material for each ceramics process unit (percent by weight expressed as a decimal fraction); • Annual mass of each carbonatebased raw material charged to each ceramics process unit (tons); and • The decimal fraction of calcination achieved for each carbonate-based raw material for each ceramics process unit (percent by weight expressed as a decimal fraction). 2. Summary of Comments and Responses on Subpart ZZ This section summarizes the major comments and responses related to the proposed subpart ZZ. The EPA previously requested comment on the addition of ceramics manufacturing sources category as a new subpart to part 98 in the 2022 Data Quality Improvements Proposal. The EPA received some comments for subpart ZZ on the 2022 Data Quality Improvements Proposal; the majority of these comments were previously addressed in the preamble to the 2023 Supplemental Proposal, wherein the EPA proposed to add new subpart ZZ for ceramics manufacturing (see section III.E. of the E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations preamble to the 2023 Supplemental Proposal). The EPA received additional comments regarding the proposed subpart ZZ following the 2023 Supplemental Proposal. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to subpart ZZ. Comments: One commenter objected to the EPA’s inclusion of the brick manufacturing industry in proposed subpart ZZ. The commenter asserted that GHG emissions from the brick industry represent only about 0.027 percent of U.S. anthropogenic emissions, stating that any relative improvement in accuracy of emissions would not change the fact that GHG emissions from brick manufacturing are a very small fraction of the national total. The commenter provided a number of reasons to exclude brick manufacturing from subpart ZZ. First, the commenter contested the EPA’s assumption that all ceramics manufacturing use materials with significant carbonate content. The commenter stated that the materials used for the production of brick are low carbonate clay and shale materials that should not be characterized as ‘‘carbonate-based materials,’’ and that the various processes used to prepare raw materials and to form and fire brick are such that higher carbonate materials cannot be used. The commenter added that high carbonate materials can result in durability problems of the brick, ranging from cosmetic ‘‘lime pops’’ to scenarios where the brick can actually fail in service. The commenter further stated that the majority production of brick in the United States is red bodied brick, and therefore the use of carbonates including limestone are undesirable, due to bleaching of the red color during firing. The commenter explained that the EPA’s proposal assumes a carbonate content of 10–15 percent, whereas tested averages for brick making materials average 0.58 percent. The commenter provided a table of carbonate brick values based on testing from the NBRC (National Brick Research Center at Clemson University). The commenter stated that, as such, the actual brick making carbonate percentages are only about 3.8–5.8 percent (0.58 percent divided by 10 percent and 15 percent, respectively) of the carbonate material percentages in the proposed rule. The commenter VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 estimated that based on this determination, the inclusion of carbonate process emissions would only increase reported emissions from a facility by about 2.10 percent, and few, if any, additional sites not already reporting exceeding the 25,000 mtCO2e reporting threshold would be required to report. The commenter added that even if facilities do not meet the threshold, the added requirements would impose on all sites additional testing and measurement requirements to determine if they exceed the reporting threshold. The commenter stated that the associated costs do not justify the requirements. The commenter stated that a limited number of brickmaking sites add small amounts of carbonates to some of their products for various reasons. The commenter explained that some manufacturers add barium carbonate to the brick body mix to prevent soluble salts from forming on the final product. In such cases, the commenter noted that barium carbonate is added typically in the range of 0.05 to 0.1 percent. The commenter also stated that sodium carbonate (added in the range of 0.5 percent) is sometimes used to improve the uptake of water during the brick forming process. The commenter asserted that in such cases, if the additional usages of carbonates are significant, they already would be reported under subpart U. The commenter noted that the EPA’s existing methods for estimating GHG emissions from the brick manufacturing industry are good enough to adequately inform the Agency’s policy/regulatory decision making and to satisfy the EPA’s desire and obligation to maintain an accurate national GHG emissions inventory. The commenter suggested that the EPA could, in lieu of annual reporting, issue a one-time information collection request. Response: The EPA has considered the information provided by the commenter and is finalizing the addition of the ceramics category to include the brick industry. Consistent with the other source categories of 40 CFR part 98, requiring annual reporting of data for ceramics facilities is preferred to a one-time information collection request. The collection of annual data will help the EPA to understand changes in industry emissions and trends over time. The snapshot of information provided by a one-time information collection request would not provide the type of ongoing information which could inform potential legislation or EPA policy. Collecting annual data also allows us to incorporate accurate time-series PO 00000 Frm 00075 Fmt 4701 Sfmt 4700 31875 emissions changes for the ceramics industry in the GHG Inventory and other EPA analyses. Further, including brick manufacturing in the ceramics source category is consistent with the 2006 IPCC Guidelines for National Greenhouse Gas Inventories.45 While the commenter asserts that brick manufacturing is a small percentage of the total national GHG emissions, the ceramics subpart would cover more industries than just brick manufacturing and is anticipated to cover emissions comparable to other existing subparts. We have included both an emissions threshold and a carbonate use threshold in order to exempt small facilities or those with minor emissions. Rather than exempting the brick industry from the ceramics subpart entirely, we have taken the commenter’s concerns into account and are modifying the definition of the source category such that the subpart ‘‘would apply to facilities that annually consume at least 2,000 tons of carbonates, either as raw materials or as a constituent in clay . . .’’. This is in contrast to the original proposed definition which included the phrase ‘‘or 20,000 tons of clay.’’ This revised carbonate use threshold will exclude and thus avoid the reporting burden for facilities that use low annual quantities of carbonates, such as brick manufacturers that use low-carbonate clay. Facilities could estimate their carbonate usage to determine their applicability for whether they meet this carbonate use threshold by multiplying the annual amount of clay consumed as a raw material (and heated to calcination) by the weight fraction of carbonates contained in the clay. Comment: One commenter objected to the proposed measurement protocols of subpart ZZ and indicated that the methods are infeasible for brick manufacturing materials. The commenter stated that the proposal cites ‘‘suitable chemical analysis methods include using an x-ray fluorescence standard method.’’ The commenter asserted that the use of x-ray fluorescence requires a minimum of at least 2.0 percent of any single carbonate material to speciate and determine an amount, which is higher than the total of all carbonates in brick making material, which the commenter 45 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 3, Industrial Processes and Product Use, Mineral Industry Emissions. 2006. Prepared by the National Greenhouse Gas Inventories Programme, Eggleston H.S., Buendia L., Miwa K., Ngara T. and Tanabe K. (eds). Published: IGES, Japan. www.ipcc-nggip.iges.or.jp/public/ 2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_ Industry.pdf. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31876 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations provided as 0.58 percent based on testing. The commenter stated that for brick manufacturing, an alternate measurement of total carbonates such as ASTM E1915 Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials for Carbon, Sulfur, and Acid-Base Characteristics (2020) 46 and CO2e calculation would be a necessary option. The commenter suggested a simpler option would be to develop a default percentage of carbonate in brickmaking raw materials, or an AP–42, Compilation of Air Pollutant Emissions Factors type metric allowing a direct calculation of CO2e emissions per product throughput tonnage. The commenter contended that this would still yield sufficiently accurate results and suggested that the historical testing data could be the basis for this option. Response: Upon careful review and consideration, the EPA has considered the information provided by the commenter and will finalize 40 CFR 98.524(b) to allow for other industry standards (i.e., x-ray fluorescence test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API)) as described in 40 CFR 98.524(d) to allow for the flexibility of using the most appropriate standard test method. Furthermore, following consideration of the commenter’s recommendation that the EPA include a default carbonate percentage, we are revising 40 CFR 98.524(b) to include a default value of 0.005 for each carbonate material where it is determined that the mass fraction is below the detection limit of available testing standards. The 0.005 value (0.5 percent) is consistent with the example limestone mass fraction that was provided by the Brick Industry Association.47 Furthermore, the EPA’s research into carbonate testing standards revealed that 0.01 (1 percent) is an example detection limit for existing standards (e.g., ASTM F3419–22, Standard Test Method for Mineral Characterization of Equine Surface Materials by X-Ray Diffraction (XRD) Techniques (2022) 48). In scientific settings, it is a common practice to assume that a value of one half the detection limit when concentrations are too low to accurately measure. Comment: One commenter stated that the proposed rule requirements to report 46 Available at https://www.astm.org/e191520.html. Accessed January 9, 2024. 47 See Docket ID. No. EPA–HQ–OAR–2019–0424– 0332 at www.regulations.gov. 48 Available at https://www.astm.org/f341922.html. Accessed January 9, 2024. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 on a unit-by-unit basis instead of facility wide reporting would impose unnecessary burdens on the brick industry. The commenter asserted that most activities (natural gas billing, clay hauling deliveries, material preparation logs, etc.) are done on a per-site basis. The commenter added that there is no benefit to requiring reporting to be done on a per unit basis, and a per site basis should be adequate for determining if emissions exceed the 25,000 metric ton CO2e reporting threshold. Response: The EPA routinely collects unit-level capacity data for process equipment in 40 CFR part 98. These unit-level data are essential for quantifying actual GHG emissions from the facility (e.g., the carbon balance method for estimating emissions relies on the actual quantities of carbonatebased raw materials charged to the ceramics process units, not just those delivered to the facility). Furthermore, we use these data to perform statistical analyses as part of our verification process, which allows us to develop ranges of expected emissions by emission source type and successfully identify outliers in the reported data. We disagree that there will be no benefit to reporting on a unit-level basis, as this information will improve the EPA’s verification of reported emissions and will provide a more accurate facilitylevel and national-level emissions profile for the industry. IV. Final Revisions to 40 CFR Part 9 The EPA is finalizing the proposed amendment to 40 CFR part 9 to include the OMB control number issued under the PRA for the ICR for the GHGRP. The EPA is amending the table in 40 CFR part 9 to list the OMB approval number (OMB No. 2060–0629) under which the ICR for activities in the existing part 98 regulations that were previously approved by OMB have been consolidated. The EPA received no comments on the proposed amendments to 40 CFR part 9 and is finalizing the change as proposed. This codification in the CFR satisfies the display requirements of the PRA and OMB’s implementing regulations at 5 CFR part 1320. V. Effective Date of the Final Amendments As proposed in the 2023 Supplemental Proposal, the final amendments will become effective on January 1, 2025. As provided under the existing regulations at 40 CFR 98.3(k), the GWP amendments to table A–1 to subpart A will apply to reports submitted by current reporters that are submitted in calendar year 2025 and PO 00000 Frm 00076 Fmt 4701 Sfmt 4700 subsequent years (i.e., starting with reports submitted for RY2024 on or before March 31, 2025). The revisions to GWPs do not affect the data collection, monitoring, or calculation methodologies used by these existing reporters. All other final revisions, which apply to both existing and new reporters, will be implemented for reports prepared for RY2025 and submitted March 31, 2026. Reporters who are newly subject to the rule (facilities that have not previously reported to the GHGRP), either due to final revisions that change what facilities must report under the rule (e.g., newly subject to subparts I or P or subparts WW, XX, YY, or ZZ), or due to the revisions to GWPs in table A–1 to subpart A, will be required to implement all requirements to collect data, including any required monitoring and recordkeeping, on January 1, 2025. This final rule includes new and revised requirements for numerous provisions under various aspects of GHGRP, including revisions to applicability and updates to reporting, recordkeeping, and monitoring requirements. Further, as explained in section I.B. and this section of this preamble, it amends numerous sections of part 98 for various specific reasons. Therefore, this final rule is a multifaceted rule that addresses many separate things for independent reasons, as detailed in each respective section of this preamble. We intended each portion of this rule to be severable from each other, though we took the approach of including all the parts in one rulemaking rather than promulgating multiple rules to amend each part of the GHGRP. For example, the following portions of this rulemaking are mutually severable from each other, as numbered: (1) revisions to General Provisions, including updates to GWPs in table A–1 to subpart A of part 98 in section III.A.1. of this preamble, (2) revisions to applicability to subparts G (Ammonia Manufacturing), P (Hydrogen Production), and Y (Petroleum Refineries) to address non-merchant hydrogen production in sections III.E., III.I., and III.M.; (3) revisions to applicability to subparts Y and WW (Coke Calciners) to address stand-alone coke calcining operations; (4) revisions to subparts PP (Carbon Dioxide Suppliers) and new subpart VV (Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916) in sections III.V. and III.Z.; (5) revisions to applicability in subparts UU (Injection of Carbon Dioxide) and subpart VV in sections E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations III.Z. and III.AA., (6) other regulatory amendments discussed in section III. and IV. of this preamble, and (7) confidentiality determinations as discussed in section VI. of this preamble. Each of the regulatory amendments in section III. is severable from all the other regulatory amendments in that section, and each of the confidentiality determinations in section VI. is also severable from all the other determinations in that section. If any of the above portions is set aside by a reviewing court, then we intend the remainder of this action to remain effective, and the remaining portions will be able to function absent any of the identified portions that have been set aside. Moreover, this list is not intended to be exhaustive, and should not be viewed as an intention by the EPA to consider other parts of the rule not explicitly listed here as not severable from other parts of the rule. lotter on DSK11XQN23PROD with RULES2 VI. Final Confidentiality Determinations This section provides a summary of the EPA’s final confidentiality determinations and emission data designations for new and substantially revised data elements included in these final amendments, certain existing part 98 data elements for which no determination has been previously established, certain existing part 98 data elements for which the EPA is amending or clarifying the existing confidentiality determination, and the EPA’s final reporting determinations for inputs to equations included in the final amendments. This section also summarizes the major comments and responses related to the proposed confidentiality determinations, emission data designations, and reporting determinations for these data elements. The EPA is not taking final action on any requirements for subpart W (Petroleum and Natural Gas Systems) in this final rule, therefore, we are not taking any action on confidentiality determinations or reporting determinations proposed for data elements in subpart W of part 98 in the 2022 Data Quality Improvements Proposal. See section I.C. of this preamble for a discussion of the EPA’s actions regarding subpart W. Additionally, we are not taking any final action on proposed subpart B (Energy Consumption) in this final rule; therefore we are not taking any action on confidentiality determinations proposed in the 2023 Supplemental Proposal for subpart B. See section III.B. of this preamble for additional information on subpart B. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 For all remaining data elements included in the 2022 Data Quality Improvements Proposal or 2023 Supplemental Proposal, this section identifies any changes to the proposed confidentiality determinations, emissions data designations, or reporting determinations in the final rule. A. EPA’s Approach To Assess Data Elements In the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, the EPA proposed to assess data elements for eligibility of confidential treatment using a revised approach, in response to Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356 (2019) (hereafter referred to as Argus Leader).49 The EPA proposed that the Argus Leader decision did not affect our approach to designating data elements as ‘‘inputs to emission equations’’ or our previous approach for designating new and revised reporting requirements as ‘‘emission data.’’ We proposed to continue identifying new and revised reporting elements that qualify as ‘‘emission data’’ (i.e., data necessary to determine the identity, amount, frequency, or concentration of the emission emitted by the reporting facilities) by evaluating the data for assignment to one of the four data categories designated by the 2011 Final CBI Rule (76 FR 30782, May 26, 2011) to meet the CAA definition of ‘‘emission data’’ in 40 CFR 2.301(a)(2)(i) (hereafter referred to as ‘‘emission data categories’’). Refer to section II.B. of the July 7, 2010 proposal (75 FR 39094) for descriptions of each of these data categories and the EPA’s rationale for designating each data category as ‘‘emission data.’’ For data elements designated as ‘‘inputs to emission equations,’’ the EPA maintained the two subcategories, data elements entered into e-GGRT’s Inputs Verification Tool (IVT) and those directly reported to the EPA. Refer to section VI.C. of the preamble of the 2022 Data Quality Improvements Proposal for further discussion of ‘‘inputs to emission equations.’’ In the 2022 Data Quality Improvements Proposal, for new or revised data elements that the EPA did not propose to designate as ‘‘emission data’’ or ‘‘inputs to emission equations,’’ the EPA proposed a revised approach for assessing data confidentiality. We proposed to assess each individual reporting element according to the new 49 Available in the docket for this rulemaking (Docket ID. No. EPA–HQ–OAR–2019–0424). PO 00000 Frm 00077 Fmt 4701 Sfmt 4700 31877 Argus Leader standard. So, we evaluated each data element individually to determine whether the information is customarily and actually treated as private by the reporter and proposed a confidentiality determination based on that evaluation. The EPA received several comments on its proposed approach in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. The commenters’ concerns and the EPA’s responses thereto are provided in the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424. Following consideration of the comments received, the EPA is not revising this approach and is continuing to assess data elements for confidentiality determinations as described in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. We are also finalizing the specific confidentiality determinations and reporting determinations as described in section VI.B. and VI.C. of this preamble. B. Final Confidentiality Determinations and Emissions Data Designations 1. Summary of Final Confidentiality Determinations a. Final Confidentiality Determinations for New and Revised Data Elements The EPA is making final confidentiality determinations and emission data designations for new and substantially revised data elements included in these final amendments. Substantially revised data elements include those data elements where the EPA is, in this final action, substantially revising the data elements as compared to the existing requirements. Please refer to the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal for additional information regarding the proposed confidentiality determinations for these data elements. For subparts A (General Provisions), C (General Stationary Fuel Combustion), F (Aluminum Production), G (Ammonia Manufacturing), H (Cement Production), P (Hydrogen Production), S (Lime Manufacturing), HH (Municipal Solid Waste Landfills), OO (Suppliers of Industrial Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment or Closed-Cell Foams), the EPA is not finalizing the proposed confidentiality determinations for certain data elements because the E:\FR\FM\25APR2.SGM 25APR2 31878 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations EPA is not taking final action on the requirements to report these data elements at this time (see section III. of this preamble for additional information). These data elements are listed in table 5 of the memorandum ‘‘Confidentiality Determinations and Emission Data Designations for Data Elements in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA–HQ– OAR–2019–0424. For subparts C (General Stationary Fuel Combustion) and PP (Suppliers of Carbon Dioxide), the EPA has revised its final confidentiality determinations or emissions data designations for certain data elements from proposal. For subpart PP, following consideration of public comments, the EPA has revised its final confidentiality determination for eight data elements that were proposed as ‘‘Not Eligible’’ to ‘‘Eligible for Confidential Treatment.’’ See section VI.B.2. of this preamble for a summary of the related comments and the EPA’s response. For subpart C, we identified two revised data elements where the EPA had inadvertently proposed to place the revised version of the data elements into a different emissions data category than the existing version of the data elements (i.e., proposed moving the data elements from one category of emissions data into a different category of emissions data). The EPA has corrected the placement of these data elements from ‘‘Facility and Unit Identifier Information’’ to ‘‘Emissions.’’ Table 6 of this preamble lists the data elements where the EPA has revised its final confidentiality determinations or emissions data designations as compared to the 2022 Data Quality Improvements Proposal. TABLE 6—DATA ELEMENTS FOR WHICH THE EPA IS REVISING THE FINAL CONFIDENTIALITY DETERMINATIONS OR EMISSION DATA DESIGNATIONS Subpart Citation in 40 CFR part 98 Data element description C 1 ..................... 98.36(c)(1)(vi) ................ C 1 ..................... 98.36(c)(3)(vi) ................ PP 2 ................... 98.426(i)(1) .................... PP 2 ................... 98.426(i)(1)(i)(C) ............ PP 2 ................... 98.426(i)(1)(i)(D) ............ PP 2 ................... 98.426(i)(1)(i)(E) ............ PP 2 ................... 98.426(i)(1)(ii) ................ PP 2 ................... 98.426(i)(2) .................... PP 2 ................... 98.426(i)(3)(i) ................. PP 2 ................... 98.426(i)(3)(ii) ................ When reporting using aggregation of units, if any of the stationary fuel combustion units burn biomass, the annual CO2 emissions from combustion of all biomass fuels combined (metric tons). When reporting using the common pipe configuration, if any of the stationary fuel combustion units burn biomass, the annual CO2 emissions from combustion of all biomass fuels combined (metric tons). If you capture a CO2 stream at a facility with a direct air capture (DAC) process unit and electricity (excluding combined heat and power (CHP)) is provided to a dedicated meter for the DAC process unit: annual quantity of electricity (generated on-site or off-site) consumed for the DAC process unit (MWh). If you capture a CO2 stream at a facility with a DAC process unit and electricity (excluding CHP) is provided to a dedicated meter for the DAC process unit: if the electricity is sourced from a grid connection, the name of the electric utility company that supplied the electricity as shown on the last monthly bill issued by the utility company during the reporting period. If you capture a CO2 stream at a facility with a DAC process unit and electricity (excluding CHP) is provided to a dedicated meter for the DAC process unit: if the electricity is sourced from a grid connection, the name of the electric utility company that delivered the electricity. If you capture a CO2 stream at a facility with a DAC process unit and electricity (excluding CHP) is provided to a dedicated meter for the DAC process unit: if the electricity is sourced from a grid connection, the annual quantity of electricity consumed for the DAC process unit (MWh). If you capture a CO2 stream at a facility with a DAC process unit and electricity (excluding CHP) is provided to a dedicated meter for the DAC process unit: if electricity is sourced from on-site or through a contractual mechanism for dedicated off-site generation, the annual quantity of electricity consumed per applicable source (MWh), if known. If you capture a CO2 stream at a facility with a DAC process unit and you use heat, steam, or other forms of thermal energy (excluding CHP) for the DAC process unit: the annual quantity of heat, steam, or other forms of thermal energy sourced from on-site or through a contractual mechanism for dedicated off-site generation per applicable energy source (MJ), if known. If you capture a CO2 stream at a facility with a DAC process unit and electricity from CHP is sourced from on-site or through a contractual mechanism for dedicated off-site generation: the annual quantity of electricity consumed for the DAC process unit per applicable energy source (MWh), if known. If you capture a CO2 stream at a facility with a DAC process unit and you use heat from CHP for the DAC process unit: the annual quantity of heat, steam, or other forms of thermal energy from CHP sourced from on-site or through a contractual mechanism for dedicated off-site generation per applicable energy source (MJ), if known. lotter on DSK11XQN23PROD with RULES2 1 In the May 26, 2011, final rule (76 FR 30782), this data element was assigned to the ‘‘Emissions Data’’ data category and determined to be ‘‘Emissions Data.’’ In the 2022 Data Quality Improvements Proposal, the data element was significantly revised, and the EPA proposed that the revised data element would be assigned to the data category ‘‘Facility and Unit Identifier’’ and would have a determination of ‘‘Emissions Data.’’ We have subsequently determined that the revisions to the data element (revising the language ‘‘if any units burn both fossil fuels and biomass’’ with ‘‘if any of the units burn biomass’’) is a clarifying change and that the data element was incorrectly assigned to a new data category. Therefore we are finalizing the revised data element in the ‘‘Emissions Data’’ data category and determining that it is ‘‘Emissions Data.’’ 2 Revised from ‘‘Not Eligible’’ to ‘‘Eligible for Confidential Treatment’’; see section VI.B.2. of this preamble. For subparts I (Electronics Manufacturing), P (Hydrogen Production), and ZZ (Ceramics Manufacturing), the EPA is finalizing revisions that include new data elements for which the EPA did not VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 propose a determination. These data elements are listed in table 7 of this preamble and table 6 of the memorandum, ‘‘Confidentiality Determinations and Emission Data Designations for Data Elements in the PO 00000 Frm 00078 Fmt 4701 Sfmt 4700 2024 Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA–HQ–OAR–2019–0424. Because the EPA has not proposed or solicited public comment on a determination for E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations these data elements, we are not 31879 finalizing confidentiality determinations for these data elements at this time. lotter on DSK11XQN23PROD with RULES2 TABLE 7—NEW DATA ELEMENTS FROM PROPOSAL TO FINAL FOR WHICH THE EPA IS NOT FINALIZING CONFIDENTIALITY DETERMINATIONS OR EMISSION DATA DESIGNATIONS Subpart Citation in 40 CFR part 98 Data element description I ......................... 98.96(y)(2)(iv) ................ P ........................ 98.166(d)(10) ................. P ........................ 98.166(d)(10)(i) .............. P ........................ 98.166(d)(10)(ii) ............. ZZ ...................... 98.526(c)(2) ................... For electronics manufacturing facilities, for the technology assessment report required under 40 CFR 98.96(y), for any destruction or removal efficiency data submitted, if you choose to use an additional alternative calculation methodology to calculate and report the input gas emission factors and by-product formation rates: a complete, mathematical description of the alternative method used (including the equation used to calculate each reported utilization and by-product formation rate). For each hydrogen production process unit, an indication (yes or no) if best available monitoring methods used in accordance with 40 CFR 98.164(c) to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater). For each hydrogen production process unit, if best available monitoring methods were used in accordance with 40 CFR 98.164(c) to determine fuel flow for each stationary combustion unit directly associated with hydrogen production, the beginning date of using best available monitoring methods. For each hydrogen production process unit, if best available monitoring methods were used in accordance with 40 CFR 98.164(c) to determine fuel flow for each stationary combustion unit directly associated with hydrogen production, the anticipated or actual end date of using best available monitoring methods. For a facility containing a ceramics manufacturing process, for each ceramics manufacturing process unit, if process CO2 emissions are calculated according to the procedures specified in 40 CFR 98.523(b), annual quantity of each carbonate-based raw material (including clay) charged (tons) (no CEMS). In a handful of cases, the EPA has made minor revisions to data elements in this final action as compared to the proposed data element included in either the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal. For certain proposed data elements, we have revised the citations from proposal to final. In other cases, the minor revisions include clarifications to the text. The EPA evaluated these data elements and how they have been clarified in the final rule to verify that the information collected has not substantially changed since proposal. These data elements are listed in table 7 of the memorandum ‘‘Confidentiality Determinations and Emission Data Designations for Data Elements in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA–HQ– OAR–2019–0424. Because the information to be collected has not substantially changed since proposal, we are finalizing the confidentiality determinations or emission data designations for these data elements as proposed. For additional information on the rationales for the confidentiality determinations for these data elements, see the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal and the memoranda ‘‘Proposed Confidentiality Determinations and Emission Data Designations for Data Elements in VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Proposed Revisions to the Greenhouse Gas Reporting Rule’’ and ‘‘Proposed Confidentiality Determinations and Emission Data Designations for Data Elements in Proposed Supplemental Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket for this rulemaking (Docket ID. No. EPA–HQ–OAR–2019–0424). For all other confidentiality determinations for the new or substantially revised data reporting elements for these subparts, the EPA is finalizing the confidentiality determinations as they were proposed. Please refer to the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal for additional information regarding these confidentiality determinations. b. Final Confidentiality Determinations and Emission Data Designations for Existing Data Elements for Which EPA Did Not Previously Finalize a Confidentiality Determination or Emission Data Designation The EPA is finalizing all confidentiality determinations as they were proposed for other part 98 data reporting elements for which no determination has been previously established. The EPA received no comments on the proposed determinations. Please refer to the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal for additional PO 00000 Frm 00079 Fmt 4701 Sfmt 4700 information regarding the proposed confidentiality determinations. c. Final Confidentiality Determinations for Existing Data Elements for Which the EPA is Amending or Clarifying the Existing Confidentiality Determination The EPA is finalizing as proposed all confidentiality determinations for other part 98 data reporting elements for which the EPA proposed to amend or clarify the existing confidentiality determinations. The EPA received no comments on the proposed determinations. Please refer to the preamble to the 2022 Data Quality Improvements Proposal for additional information regarding the proposed confidentiality determinations. 2. Summary and Response to Public Comments on Proposed Confidentiality Determinations The EPA received several comments related to the proposed confidentiality determinations. The EPA received minimal comments on the proposed confidentiality determinations for all new or substantially revised data elements, except certain data elements in subparts PP (Suppliers of Carbon Dioxide) and VV (Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916) as described in this section. Additional comments may be found in the EPA’s comment response document in Docket ID. No. EPA–HQ–OAR–2019– E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31880 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 0424. For subparts PP and VV, we received comments questioning the proposed confidentiality determination of certain new and substantially revised data elements in each subpart, including requests that the data elements be treated as confidential. Summaries of the major comments and the EPA’s responses thereto are provided below. Additional comments and the EPA’s responses may be found in the comment response document noted above. Comment: One commenter contended that public disclosure of the annual quantity of electricity consumed to power the DAC process unit and natural gas used for thermal energy could undermine the commercial deployment of DAC. The commenter stated that this information should be kept as confidential. The commenter explained that power in a DAC facility is one of the main operating expenses and power consumption is directly related to power cost. The commenter stated that a comprehensive understanding of a DAC unit’s power demand, coupled with a basic understanding of the clean power markets in the region where the DAC facility is located, could be used to estimate the DAC power cost. The commenter contended that this knowledge, if available to a competitor or provider of clean power, would affect business-to-business contract negotiations, allow for speculation on potential profit margins on captured CO2 volumes, and negatively impact the ability of a DAC operator to procure clean power at competitive rates. The commenter added that many carbon capture technologies will utilize natural gas to provide the thermal energy needed to drive the CO2 capture process, including DAC facilities. The commenter explained contract negotiations for the supply of natural gas for DAC facilities are competitive and a major operating cost for a DAC facility and information on the annual amount of natural gas consumed by a DAC facility, if available to a competitor or natural gas supplier, will affect the ability of a DAC operator to contract for responsibly sourced natural gas supply at a competitive cost. The commenter requested that natural gas consumption be declared CBI. The commenter added that they still supported the requirement to report on whether flue gas is also captured by the DAC process unit as this requirement allows for a clear distinction of CO2 captured from the process versus CO2 captured from the air, increasing public trust in reported CO2 volumes. Response: The EPA proposed that 12 new subpart PP data elements in 40 CFR 98.426(i) specific to DAC facilities VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 would not be eligible for confidential treatment. These data elements included: the annual quantities of onsite and off-site electricity consumed for the DAC process unit; the annual quantities of heat, steam, other forms of thermal energy, and combined heat and power (CHP) consumed by the DAC process unit; the state and county where the facility with the DAC process unit is located; the name of the electric utility company that supplied and delivered the electricity if electricity is sourced from a grid connection; the annual quantity of electricity consumed by the DAC process unit supported by billing statements; the annual quantity of electricity, heat, and CHP consumed for the DAC process unit by each applicable source; and whether flue gas is also captured by the DAC process unit when electricity or CHP is generated onsite from natural gas, coal, or oil. The EPA’s proposed determinations were based on research that indicated the proposed data elements are not customarily and actually treated as private by the reporter. We note that this, rather than competitive harm, is now the standard for treating reported data elements as ‘‘Eligible for Confidential Treatment’’ or ‘‘Not Eligible’’ based on the decision in Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356 (2019). While the commenter explains that there may be competitive harm from releasing electricity and natural gas consumption data in 40 CFR 98.426, they do not clearly demonstrate whether such data are customarily and actually treated as confidential. Following receipt of public comment, the EPA conducted additional research on the public availability of energy use data for DAC and other facilities, and determined that, with the exception of the state and county where the DAC facility is located, the other proposed data elements are not consistently available to the public at this time. As DAC is a nascent field, there are not yet many examples of such facilities to support a determination as to whether the other proposed data elements are typically and actually held confidential. The EPA, therefore, partially agrees with the commenter that certain data elements for DAC process unit energy requirements in 40 CFR 98.426(i) may be treated as confidential by certain facilities. The EPA is, therefore, making a determination of ‘‘Eligible for Confidential Treatment’’ for certain data elements. Specifically, the EPA is finalizing the rule with all new data elements in 40 CFR 98.426(i) having the categorical determination of ‘‘Eligible for Confidential Treatment’’ PO 00000 Frm 00080 Fmt 4701 Sfmt 4700 except for proposed 40 CFR 98.426(i)(1)(i)(A) and (B), the state and county where the DAC process unit is located, and certain information reported under 40 CFR 98.426(i)(1) through (3), which requires the reporter to indicate each applicable energy source type (e.g., natural gas, oil, coal, nuclear) and provide an indication of whether flue gas is captured (proposed 40 CFR 98.426(i)(1)), respectively. The rule is being finalized with the determination that these four data elements are not eligible for confidential treatment. The requirements to report the state and county are similar to data required to be reported under 40 CFR 98.3(c)(1) that was designated as ‘‘emission data,’’ which under CAA section 114 is not entitled to confidential treatment (76 FR 30782, May 26, 2011; CBI Memo, April 29, 2011). Furthermore, the EPA has previously determined that indication of source is not confidential (77 FR 48072, August 13, 2012). Regarding reporting whether flue gas is captured, the EPA has previously determined that an indication of flue gas is ‘‘Not Eligible’’ (76 FR 30782, May 26, 2011). While the source of energy would be ‘‘Not Eligible’’ for confidential treatment, the actual quantities of energy reported under 40 CFR 98.426(i)(1) through (3) would be ‘‘Eligible for Confidential Treatment.’’ The EPA will consider revising the confidentiality status of the energy consumption data elements in the future, as more DAC facilities begin operating and we have a better understanding of how these data are customarily treated. For example, if DAC facilities begin customarily sharing their energy consumption information to advertise their energy efficiency, we may consider revising the confidentiality status to ‘‘No Determination’’ or ‘‘Not Eligible for Confidential treatment.’’ Comment: The EPA received several comments regarding the confidential treatment of the proposed EOR OMP at 40 CFR 98.488. Several commenters strongly supported the publishing of non-confidential data related to anthropogenic CO2 volumes permanently stored in in CO2–EOR operations, including the EOR OMP. Commenters compared the EOR OMP to the MRV plan issued or required under subpart RR, noting that the plans serve very similar purposes and include a geologic characterization of the storage location, information about wells within the storage site area, operations history, monitoring programs, and calculation and quantification methods used to determine the total amount of CO2 E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 stored in the storage site. One commenter strongly objected to the public disclosure of the OMP. The commenter stated that, unlike an MRV which must receive approval by the EPA under subpart RR, there is no such approval required for an OMP under subpart VV, which is appropriate given the differences in the subpart methodologies. The commenter added that reporting entities are currently free to exercise discretion to publicly disclose their OMPs. Response: The EPA disagrees with the commenter. The EPA’s review and approval of a document does not determine whether the document is eligible for confidential treatment. The EPA proposed that the OMP is not eligible for confidential treatment because it does not consider the data elements in the OMP to be customarily and actually treated as confidential. We note that this, rather than whether the EPA reviews and approves a submission, is the standard for confidentiality of reported data elements based on the Argus Leader decision. For example, the OMP shall include geologic characterization of the EOR complex, a description of the facilities within the CO2–EOR project, a description of all wells and other engineered features in the CO2–EOR project, the operations history of the project reservoir, descriptions of containment assurance and the monitoring plan, mass of CO2 previously injected and other information required in the CSA/ANSI ISO 27916:19 standard. This information is normally available to the public through geologic records, construction and operating permitting files, well permits, tax records, and other public records. Furthermore, such information is available in EPAapproved subpart RR MRV plans which have been determined to be notconfidential and are consistently made publicly available on the EPA’s website. That the EPA does not have a role in approving the OMP does not mean that the content itself is typically and actually held confidential. C. Final Reporting Determinations for Inputs to Emission Equations In the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, the EPA proposed to assign several data elements to the ‘‘Inputs to Emission Equation’’ data category. As discussed in section VI.B.1. of the preamble to the 2022 Data Quality Improvements Proposal, the EPA determined that the Argus Leader decision does not affect our approach for handling of data elements assigned VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 to the ‘‘Inputs to Emission Equations’’ data category. Data assigned to the ‘‘Inputs to Emission Equations’’ data category are assigned to one of two subcategories, including ‘‘inputs to emission equations’’ that must be directly reported to the EPA, and ‘‘inputs to emission equations’’ that are not reported but are entered into the EPA’s Inputs Verification Tool (IVT). The EPA received no comments specific to the proposed reporting determinations for inputs to emission equations in the proposed rules. Additional information regarding these reporting determinations may be found in section VI.C. of the preamble to the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. The EPA is finalizing the reporting determinations for data elements that the EPA proposed to assign to the ‘‘Inputs to the Emission Equation’’ data category as they were proposed for all subparts with the exception of certain records proposed for subparts G (Ammonia Production), P (Hydrogen Production), S (Lime Production), and HH (Municipal Solid Waste Landfills). For subparts G, P, and S, the new and substantially revised data elements were not proposed to be included in the reporting section of those subparts but were instead to be retained as records to be input into the EPA’s IVT, and the EPA did not evaluate these data elements further. The EPA is not taking final action on these inputs into IVT because the EPA is not taking final action on the requirement to retain these data elements as records (see section III. of this preamble for additional information.) For subpart HH, the EPA is not finalizing the proposed reporting determinations for certain data elements because the EPA is not taking final action on the requirements to report these data elements at this time (see section III. of this preamble for additional information). These data elements are listed in table 3 of the memorandum ‘‘Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424. In a handful of cases, the EPA has made minor revisions to data elements assigned to the ‘‘Inputs to Emissions Equations’’ data category in this final action as compared to the proposed data element included in the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal. For certain proposed data elements, we have PO 00000 Frm 00081 Fmt 4701 Sfmt 4700 31881 revised the citations from proposal to final. In other cases, the minor revisions include clarifications to the text. The EPA evaluated these inputs to emissions equations and how they have been clarified in the final rule to verify that the data element has not substantially changed since proposal. These data elements and how they have been clarified in the final rule are listed in table 4 of the memorandum ‘‘Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in the 2024 Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket to this rulemaking, Docket ID. No. EPA– HQ–OAR–2019–0424. Because the input has not substantially changed since proposal, we are finalizing the proposed reporting determinations for these data elements as proposed. For additional information on the rationale for the reporting determinations for the data elements, see the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal and the memorandums ‘‘Proposed Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in Proposed Revisions to the Greenhouse Gas Reporting Rule’’ and ‘‘Proposed Reporting Determinations for Data Elements Assigned to the Inputs to Emission Equations Data Category in Proposed Supplemental Revisions to the Greenhouse Gas Reporting Rule,’’ available in the docket for this rulemaking (Docket ID. No. EPA–HQ– OAR–2019–0424). For all other reporting determinations for the data elements assigned to the ‘‘Inputs to Emission Equations’’ data category, the EPA is finalizing the reporting determinations as they were proposed. Please refer to the preamble to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental Proposal for additional information. VII. Impacts and Benefits of the Final Amendments This section of the preamble examines the costs and economic impacts of the final rule and the estimated impacts of the rule on affected entities, in addition to the benefits of the final rule. The revisions in this final rule are anticipated to increase burden in cases where the amendments expand the applicability, monitoring, or reporting requirements of part 98. In some cases, the final amendments are anticipated to decrease burden where we streamlined the rule to remove notification or reporting requirements or simplify monitoring and reporting requirements. The final rule consolidates amendments E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31882 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations from the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal that revise 32 subparts that directly affect 30 industries—including revisions to update the GWPs in table A–1 to subpart A of part 98 that affect the number of facilities required to report under part 98; revisions to implement five new source categories or to expand existing source categories that may require facilities to newly report or to report under new provisions; and revisions to add new reporting requirements to a number of subparts that will improve the quality of the data collected under part 98. The bulk of costs associated with the final rule includes those costs to facilities that would be required to newly report under part 98 (subparts I, P, W, DD, HH, II, OO, TT, WW, XX, YY, and ZZ). However, the majority of subparts affected will reflect a modest increase in burden to individual reporters. As discussed in the preamble to the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, in several cases the final rule amendments are anticipated to result in a decrease in burden. In some cases we have quantified where the final rule would result in a decrease in burden for certain reporters, but in other cases we were unable to quantify this decrease. The final revisions also include minor amendments, corrections, and clarifications, including simple revisions of requirements such as clarifying changes to definitions, calculation methodologies, monitoring and quality assurance requirements, and reporting requirements. These revisions clarify part 98 to better reflect the EPA’s intent, and do not present any additional burden on reporters. The impacts of the final rule generally reflect an increase in burden for most subparts. The EPA received a number of comments on the proposed revisions and the impacts of the proposed revisions in both the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. See the document ‘‘Summary of Public Comments and Responses for 2024 Final Revisions and Confidentiality Determinations for Data Elements under the Greenhouse Gas Reporting Rule’’ in Docket ID. No. EPA–HQ–OAR–2019– 0424 for a complete listing of all comments and responses related to the impacts of the proposed rules. Following consideration of these comments, the EPA has, in some cases, VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 revised the final rule requirements and updated the impacts analysis to reflect these changes. As noted in section I.C. of this preamble, although the EPA proposed amendments to subpart W (Petroleum and Natural Gas Systems) in the 2022 Data Quality Improvements Proposal, this final rule does not address implementation of these revisions to subpart W, which the EPA is reviewing in concurrent rulemakings. Additionally, as stated in section III.B. of this preamble, the EPA is not taking final action on its proposed amendments to add a source category for collection of data on energy consumption (subpart B) at this time. Accordingly, the impacts of the final rule do not reflect the costs for these proposed revisions. For some subparts, we are not taking final action on revisions to calculation, monitoring, or reporting requirements that would have required reporters to collect or submit additional data. For example, for subpart C (General Stationary Fuel Combustion), we are not taking final action on proposed revisions to (1) add new reporting for the unit type, maximum rated heat input capacity, and an estimate of the fraction of the total annual heat input from each unit in either an aggregation of units or common pipe configuration (excluding units less than 10 mmBtu/ hour); and (2) add new reporting to identify whether any unit in the configuration (individual units, aggregation of units, common stack, or common pipe) is an EGU, and, for multi-unit configurations, an estimated decimal fraction of total emissions from the group that are attributable to EGU(s) included in the group. For subparts G (Ammonia Production), P (Hydrogen Production), S (Lime Production), and HH (Municipal Solid Waste Landfills) we are not taking final action on certain revisions to the calculation methodologies that would have revised how data is collected and reported in eGGRT. Similarly, we are not taking final action on certain data elements that were proposed to be added to subparts A (General Provisions), F (Aluminum Production), G (Ammonia Production), H (Cement Production), P, S (Lime Production), HH, OO (Suppliers of Industrial Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment and Closed-Cell Foams). Therefore, the final burden for these subparts has been revised to PO 00000 Frm 00082 Fmt 4701 Sfmt 4700 reflect only those requirements that are being finalized, and is lower than proposed. In a few cases, the EPA has adjusted the burden of the final rule to account for additional costs associated with the final rule. In these cases, we have made minor adjustments to the reporting and recordkeeping requirements in the final rule. Specifically, we are finalizing changes from the proposed rule that would add 8 new data elements to subparts I, P, DD, and ZZ (see section III. of this preamble for additional information). The final rule burden estimate has been adjusted to include additional time and labor for these activities, which the EPA estimates is minimal for the reasons described in section III. of this preamble. Finally, the burden for the activities in the final rule has been adjusted to reflect updates to the estimated number of affected reporters based on a review of data from RY2022 reporting. As discussed in section V. of this preamble, the final rule will be implemented on January 1, 2025, and will apply to RY2025 reports. Costs have been estimated over the three years following the year of implementation. One-time implementation costs are incorporated into first year costs, while subsequent year costs represent the annual burden that will be incurred in total by all affected reporters. The incremental implementation labor costs for all subparts include $2,684,681 in RY2025, and $2,671,831 in each subsequent year (RY2026 and RY2027). The incremental implementation labor costs over the next three years (RY2025 through RY2027) total $8,028,343. There is an additional incremental burden of $2,733,937 for capital and O&M costs in RY2025 and in each subsequent year (RY2026 and RY2027), which reflects changes to applicability and monitoring for subparts I, P, W, V, Y, DD, HH, II, OO, TT, UU and new subparts VV, WW, XX, YY, and ZZ. The incremental nonlabor costs for RY2025 through RY2027 total $8,201,812 over the next three years. The incremental burden is summarized by subpart for the rule changes that are finalized for initial and subsequent years in table 8 of this preamble. Note that subparts A, U, FF, and RR only include revisions that are clarifications or harmonizing changes that would not result in any changes to burden, and are not included in table 8 of this preamble. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31883 TABLE 8—ANNUAL INCREMENTAL BURDEN OF THE FINAL RULE, BY SUBPART Labor costs Number of affected facilities Initial year Subsequent years C—General Stationary Fuel Combustion Sources a ........................................ Facilities Reporting only to Subpart C ............................................................. Facilities Reporting to Subpart C plus another subpart .................................. G—Ammonia Manufacturing ........................................................................... H—Cement Production .................................................................................... I—Electronics Manufacturing b c ....................................................................... N—Glass Production ....................................................................................... P—Hydrogen Production b ............................................................................... Q—Iron and Steel Production ......................................................................... S—Lime Manufacturing ................................................................................... V—Nitric Acid Production d e ............................................................................ W—Petroleum and Natural Gas Systems d ..................................................... X—Petrochemical Production .......................................................................... Y—Petroleum Refineries f ................................................................................ AA—Pulp and Paper Manufacturing ............................................................... BB—Silicon Carbide Production ...................................................................... DD—Electrical Transmission b ......................................................................... GG—Zinc Production ....................................................................................... HH—Municipal Solid Waste Landfills b ............................................................ II—Industrial Wastewater Treatment d ............................................................. OO—Suppliers of Industrial Greenhouse Gases a .......................................... PP—Suppliers of Carbon Dioxide ................................................................... QQ—Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams ...................................... SS—Electrical Equipment Manufacture or Refurbishment .............................. TT—Industrial Waste Landfills b d .................................................................... UU—Injection of Carbon Dioxide g .................................................................. VV—Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916 g ................................................................................. WW—Coke Calciners ...................................................................................... XX—Calcium Carbide Production .................................................................... YY—Caprolactam, Glyoxal, and Glyoxylic Acid Production ............................ ZZ—Ceramics Manufacturing .......................................................................... ........................ 133 177 29 94 48 101 114 121 71 1 188 31 57 1 1 95 5 1,129 2 121 22 ........................ ($1,446) (979) 119 1,999 19,651 2,074 7,497 1,485 1,186 (2,680) 2,433,058 618 (6,133) 104 20 15,278 20 84,651 5,288 6,884 872 ........................ ($1,446) (979) 119 1,999 18,023 2,074 7,497 1,485 1,186 (2,680) 2,433,058 618 (6,133) 104 20 15,278 20 81,793 4,713 6,884 872 ........................ ........................ ........................ ........................ ........................ $62 ........................ 2,561 ........................ ........................ (11,085) 2,717,864 ........................ (3,930) ........................ ........................ 3,119 ........................ 374 3,077 62 ........................ 33 5 1 2 249 358 4,853 (1,886) 249 358 3,934 (1,886) ........................ ........................ 62 (125) 2 15 1 6 25 1,882 37,847 2,849 12,285 56,678 3,443 34,525 2,627 11,089 52,987 250 19,649 62 374 1,559 Total .......................................................................................................... ........................ 2,684,681 2,671,831 2,733,937 Subpart Capital and O&M a Reflects reduced burden due to revisions to simplify calculation methods and remove reporting requirements. to reporters that may currently report under existing subparts of part 98 and that are newly subject to reporting under part 98. subsequent year costs for subpart I. Subpart I subsequent year costs include $17,794 in Year 2 and $18,252 in Year 3. d Reflects burden to reporters estimated to be affected due to revisions to table A–1 to subpart A only. e Reflects changes to the number of reporters able to off-ramp from reporting under the part 98 source category. f Reflects changes to the number of reporters with coke calciners reporting under subpart Y that would be required to report under proposed subpart WW. g Reflects changes to the number of reporters reporting under subpart UU who will begin submitting reports under new subpart VV in each year. b Applies lotter on DSK11XQN23PROD with RULES2 c Average Additional details on the EPA’s review of the impacts may be found in the memorandum, ‘‘Assessment of Burden Impacts for Final Revisions to the Greenhouse Gas Reporting Rule,’’ available in Docket ID. No. EPA–HQ– OAR–2019–0424. The implementation of the final rule will provide numerous benefits for stakeholders, the Agency, industry, and the general public. The final revisions include improvements to the calculation, monitoring, and reporting requirements, incorporate new data and reflect updated scientific knowledge; provide coverage of new emissions sources and additional sectors; improve analysis and verification of collected data; provide additional data to complement or inform other EPA programs; and streamline calculation, VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 monitoring, or reporting to provide flexibility or increase the efficiency of data collection. The revisions will maintain the quality of the data collected under part 98 where continued collection of information assists in evaluation and support of EPA programs and policies under provisions of the CAA. In some cases, the amendments improve the EPA’s ability to assess compliance by revising or adding recordkeeping or reporting elements that will allow the EPA to more thoroughly verify GHG data and advance the ability of the GHGRP to provide access to quality data on greenhouse gas emissions by adding or updating emission factors, revising or adding calculation methodologies, or adding key data elements to improve the usefulness of the data. PO 00000 Frm 00083 Fmt 4701 Sfmt 4700 Because part 98 is a reporting rule, the EPA did not quantify estimated emission reductions or monetize the benefits from such reductions that could be associated with the final rule. The benefits of the final rule are based on its relevance to policy making, transparency, and market efficiency. The improvements to the GHGRP will benefit the EPA, other policymakers, and the public by increasing the completeness and accuracy of facility emissions data. Public data on emissions allows for accountability of emitters to the public. Improved facilityspecific emissions data will aid local, state, and national policymakers as they evaluate and consider future climate change policy decisions and other policy decisions for criteria pollutants, ambient air quality standards, and toxic E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31884 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations air emissions. For example, GHGRP data on petroleum and natural gas systems (subpart W of part 98) were previously analyzed to inform targeted improvements to the 2016 NSPS for the oil and gas industry and to update emission factor and activity data used for that proposal and the final NSPS, as updated in the Inventory (83 FR 52056; October 15, 2018). Similarly, GHGRP data on municipal solid waste landfills (subpart HH of part 98) were previously used to inform the development of the 2016 NSPS and EG for landfills; the EPA was able to update its internal landfills data set and consider the technical attributes of over 1,200 landfills based on data reported under subpart HH. The benefits of improved reporting also include enhancing existing voluntary programs, such as the Landfill Methane Outreach Program (LMOP), which uses GHGRP data to supplement the LMOP Landfill and Landfill Gas Energy Project Database and includes data collected from LMOP Partners about landfill gas energy projects or potential for project development. The final rule would additionally benefit states by providing improved facility-specific emissions data. Several states use GHGRP data to inform their own policymaking. For example, the state of Hawaii uses GHGRP data to establish an emissions baseline for each facility subject to their GHG Reduction Plan and to assess whether facilities meet their targets in future years. GHGRP data are also used to improve estimates of GHG emissions internationally. Data collected through the GHGRP complements the Inventory and are used to significantly improve our understanding of key emissions sources by allowing the EPA to better reflect changing technologies and emissions from a wide range of industrial facilities. Specifically, GHGRP data have been used to inform several of the updates to emission estimation methods included in the 2019 Refinement. Benefits to industry of improved GHG emissions monitoring and reporting from the amendments include the value of having standardized emissions data to present to the public to demonstrate appropriate environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reduce emissions. For example, the final rule updates the global warming potential values used under the GHGRP to reflect values from the IPCC AR5 and AR6, which are consistent with the values used under several voluntary standards and frameworks such as the GHG Protocol and Sustainability Accounting VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Standards Board (SASB), and will provide consistency for company reporting. Businesses and other innovators can use the data to determine and track their GHG footprints, find cost-saving efficiencies that reduce GHG emissions and save product, foster technologies to protect public health and the environment, and to reduce costs associated with fugitive emissions. The final rule will continue to allow for facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry and achieve and disseminate information about their environmental performance. In addition, transparent, standardized public data on emissions allows for accountability of polluters to the public who bear the cost of the pollution. The GHGRP serves as a powerful data resource and provides a critical tool for communities to identify nearby sources of GHGs and provide information to state and local governments. As discussed in section II. of this preamble, GHGRP data are easily accessible to the public via the EPA’s FLIGHT, which allows users to view and sort GHG data by location, industrial sector, and type of GHG emitted, and includes demographic data. Although the emissions reported to the EPA by reporting facilities are global pollutants, many of these facilities also release pollutants that have a more direct and local impact in the surrounding communities. Citizens, community groups, and labor unions have made use of public pollutant release data to negotiate directly with emitters to lower emissions, avoiding the need for additional regulatory action. The final rule would improve the quality and transparency of this reported data to affected communities. VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and 14094: Modernizing Regulatory Review This action is not a significant regulatory action as defined in Executive Order 12866, as amended by Executive Order 14094, and was therefore not subject to a requirement for Executive Order 12866 review. B. Paperwork Reduction Act The information collection activities in this rule have been submitted for approval to the OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned OMB number 2060– 0748, EPA ICR number 2773.02. You PO 00000 Frm 00084 Fmt 4701 Sfmt 4700 can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them. The EPA has estimated that the final rule will result in an increase in burden, specifically in cases where the amendments expand the applicability, monitoring, or reporting requirements of part 98. In some cases, the final amendments are anticipated to decrease burden where we streamlined the rule to remove notification or reporting requirements or simplify monitoring and reporting requirements. The final rule consolidates amendments from the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal that revise 31 subparts that directly affect 30 industries—including revisions to update the GWPs in table A–1 to subpart A of part 98 that affect the number of facilities required to report under part 98; revisions to implement five new source categories or to expand existing source categories that may require facilities to newly report; and revisions to add new reporting requirements that will improve the quality of the data collected under part 98. The costs associated with the final rule largely reflect the costs to facilities that would be required to newly report under part 98. However, the majority of subparts affected will reflect a modest increase in burden to existing individual reporters. Further information on the EPA’s assessment on the impact on burden can be found in the memorandum ‘‘Assessment of Burden Impacts for Final Revisions for the Greenhouse Gas Reporting Rule,’’ available in the docket for this rulemaking (Docket ID. No. EPA–HQ–OAR–2019–0424). Respondents/affected entities: Owners and operators of facilities that must report their GHG emissions and other data to the EPA to comply with 40 CFR part 98. Respondent’s obligation to respond: The respondent’s obligation to respond is mandatory and the requirements in this rule are under the authority provided in CAA section 114. Estimated number of respondents: 2,701. Frequency of response: Initially, annually. Total estimated burden: 25,647 hours (annual average per year). Burden is defined at 5 CFR 1320.3(b). Total estimated cost: $5,410,000 (annual average per year), includes $2,734,000 annualized capital or operation and maintenance costs. An agency may not conduct or sponsor, and a person is not required to E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 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. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. C. Regulatory Flexibility Act (RFA) I certify that this final action will not have a significant economic impact on a substantial number of small entities under the RFA. The small entities subject to the requirements of this action are small businesses across all sectors encompassed by the rule, small governmental jurisdictions, and small non-profits. In the development of 40 CFR part 98, the EPA determined that some small entities are affected because their production processes emit GHGs that must be reported, because they have stationary combustion units on site that emit GHGs that must be reported, or because they have fuel supplier operations for which supply quantities and GHG data must be reported. Small governments and small non-profits are generally affected because they have regulated landfills or stationary combustion units on site, or because they own a local distribution company (LDC). The EPA previously conducted screening analyses to identify impacts to small entities during the development of the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal. The EPA conducted small entity analyses that assessed the costs and impacts to small entities in three areas, including: (1) amendments that revise the number or types of facilities required to report (i.e., updates of the GHGRP’s applicability to certain sources), (2) changes to refine existing monitoring or calculation methodologies that require collection of additional data, and (3) revisions to reporting and recordkeeping requirements for data provided to the program. The analyses provided the subparts affected, the number of small entities affected, and the estimated impact to these entities based on the total annualized reporting costs of the proposed rules. Details of these analyses are presented in the memoranda, Assessment of Burden Impacts for Proposed Revisions for the Greenhouse Gas Reporting Rule (May 2022) and Assessment of Burden Impacts for Proposed Supplemental Revisions for the Greenhouse Gas Reporting Rule VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (April 2023), available in the docket for this rulemaking (Docket ID. No. EPA– HQ–OAR–2019–0424). Based on the results of these analyses, we concluded that the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal will have no significant regulatory burden for any directly regulated small entities and thus would not have a significant economic impact on a substantial number of small entities. As discussed in sections III. and VII. of this preamble, this action finalizes revisions to part 98 as proposed in the 2022 Data Quality Improvements Proposal and the 2023 Supplemental Proposal, or with minor revisions, and we have revised the cost impacts to reflect the final rule requirements and more recent data. For example, we have updated the impacts to better reflect the number of affected reporters that would be subject to the final requirements, based on a review of RY2022 data. These updates also predominantly include removing or adjusting costs where the EPA is not taking final action on specific proposed revisions, including costs associated with the addition of proposed subpart B (Energy Consumption), certain costs associated with proposed revisions to subpart W (Petroleum and Natural Gas Systems) included in the 2022 Data Quality Improvements Proposal,50 and costs associated with certain revisions to calculations, monitoring, or reporting requirements for subparts A (General Provisions), C (General Stationary Fuel Combustion), F (Aluminum Production), G (Ammonia Production), H (Cement Production), S (Lime Production), HH (Municipal Waste Landfills), OO (Suppliers of Industrial Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment and Closed-Cell Foams). Accordingly, the burden of the final rule is reduced, as compared to the proposals, for facilities that may report for these source categories, including all direct emitting facilities previously proposed to report under subpart B. The EPA has also adjusted the burden to account for additional costs from changes adopted in the final rule. Specifically, we have adjusted the reporting and recordkeeping requirements for subparts I (Electronics Manufacturing), P (Hydrogen 50 The EPA is not taking final action on any revisions to requirements for subpart W (Petroleum and Natural Gas Systems) in this final rule. See sections I.C. and VII. of this preamble for additional information regarding the EPA’s actions regarding subpart W and the impacts included in this final rule. PO 00000 Frm 00085 Fmt 4701 Sfmt 4700 31885 Production), DD (Electrical Transmission and Distribution Equipment Use), HH (Municipal Solid Waste Landfills), and ZZ (Ceramics Manufacturing) to add new data elements for annual reporting across these subparts. The estimated costs associated with the revisions to these subparts for regulated entities are minimal (less than $100 annually), and would not result in costs exceeding more than one percent of sales in any firm size category. Details of this analysis are presented in the memorandum ‘‘Assessment of Burden Impacts for Final Revisions for the Greenhouse Gas Reporting Rule,’’ available in Docket ID. No. EPA–HQ– OAR–2019–0424. The remaining revisions to the final rule include minor clarifications or adjustments to the proposed requirements that are not anticipated to increase the burdens estimated for the 2022 Data Quality Improvements Proposal and 2023 Supplemental Proposal which we previously determined would not have a significant impact on a significant number of small businesses. For these reasons, we have determined that these final revisions are consistent with our prior small entity analyses, and would impose no significant regulatory burden on any directly regulated small entities, and thus would not have a significant economic impact on a substantial number of small entities. Refer to the memorandum ‘‘Assessment of Burden Impacts for Final Revisions for the Greenhouse Gas Reporting Rule,’’ available in Docket ID. No. EPA–HQ–OAR–2019–0424 for further discussion. The EPA continues to conduct significant outreach on the GHGRP and maintains an ‘‘open door’’ policy for stakeholders to help inform the EPA’s understanding of key issues for the industries. D. Unfunded Mandates Reform Act (UMRA) This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. E. 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. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31886 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This action has tribal implications. However, it will neither impose substantial direct compliance costs on federally recognized tribal governments, nor preempt tribal law. This regulation will apply directly to facilities emitting and supplying GHGs that may be owned by tribal governments that emit GHGs. However, it will only have tribal implications where the tribal entity owns a facility that directly emits GHGs above threshold levels; therefore, relatively few (approximately 10) tribal facilities will be affected. This regulation is not anticipated to impact facilities or suppliers of additional sectors owned by tribal governments. In evaluating the potential implications for tribal entities, we first assessed whether tribes would be affected by any final revisions that expanded the universe of facilities that would report GHG data to the EPA. The final rule amendments will implement requirements to collect additional data to understand new source categories, new sources of GHG emissions or supply for specific sectors; improve the existing emissions estimation methodologies; and improve the EPA’s understanding of the sector-specific processes or other factors that influence GHG emission rates and improve verification of collected data. Of the 254 facilities that we anticipate will be newly required to report under the final revisions, we do not anticipate that there are any tribally owned facilities. As discussed in section VII. of this preamble, we expect the final revisions to table A–1 to part 98 to result in a change to the number of facilities required to report under subparts W (Petroleum and Natural Gas Systems), V (Nitric Acid Production), DD (Electrical Transmission and Distribution Equipment Use), HH (MSW Landfills), II (Industrial Wastewater Treatment), OO (Suppliers of Industrial GHGs), and TT (Industrial Waste Landfills). However, we did not identify any potential sources in these source categories that are owned by tribal entities not already reporting to the GHGRP. Similarly, although we are finalizing amendments that will require some facilities in select source categories not currently subject to the GHGRP to begin implementing requirements under the program, we have not identified, and do not anticipate that any of these affected facilities are owned by tribal governments. As a second step to evaluate potential tribal implications, we evaluated VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 whether there were any tribally owned facilities that are currently reporting under the GHGRP that will be affected by the final revisions. Tribally owned facilities currently subject to part 98 will only be subject to changes that are improvements or clarifications of requirements and that, for the most part, do not significantly change the existing requirements or result in substantial new activities because they do not require new equipment, sampling, or monitoring. Rather, tribally owned facilities would only be subject to new requirements where reporters would provide data that is readily available from company records. As such, the final revisions will not substantially increase reporter burden, impose significant direct compliance costs for tribal facilities, or preempt tribal law. Specifically, we identified ten facilities currently reporting to part 98 that are owned by six tribal parent companies. For these six parent companies, we identified facilities in the stationary fuel combustion (subpart C), cement production (subpart H), petroleum and natural gas (subpart W), electrical transmission and distribution equipment use (subpart DD), and MSW landfill (subpart HH) source categories that may be affected by the final revisions. For stationary fuel combustion, the EPA is not taking final action on proposed revisions to add reporting requirements to subpart C, but is retaining revisions that would remove certain reporting requirements. Therefore, the costs for any triballyowned facilities currently reporting to subpart C are anticipated to decrease and no facilities are anticipated to be negatively impacted. For petroleum and natural gas facilities, the EPA is not including any revisions to subpart W in this final rule (see section I.C. of this document); therefore, any triballyowned facilities currently reporting to subpart W are not anticipated to be impacted. Three parent companies include existing facilities that report only under subparts C or W, which are not anticipated to have significant impacts under this rule for the reasons discussed in this section. Therefore, the remaining facilities that could be affected by the final revisions are those that report to subparts H, DD, and HH. For the remaining three parent companies, we reviewed publicly available sales and revenue data to assess whether the costs of the final rule would be significant. Under the final rule, the costs for facilities currently reporting under subparts H, DD, or HH are anticipated to increase by less than $100 per year per subpart. Therefore, we PO 00000 Frm 00086 Fmt 4701 Sfmt 4700 were able to confirm that the costs of the final revisions would not have a significant impact for these sources. Further, based on our review of our small entity analyses (discussed in VIII.C. of this preamble), we do not anticipate the final revisions to subparts H, DD, or HH will impose substantial direct compliance costs on the remaining tribally owned entities. Although few facilities subject to part 98 are likely to be owned by tribal governments, the EPA previously sought opportunities to provide information to tribal governments and representatives during the development of the proposed and final rules for part 98 subparts that were promulgated on October 30, 2009 (74 FR 52620), July 12, 2010 (75 FR 39736), November 30, 2010 (75 FR 74458), and December 1, 2010 (75 FR 74774 and 75 FR 75076). Consistent with the 2011 EPA Policy on Consultation and Coordination with Indian Tribes,51 the EPA previously consulted with tribal officials early in the process of developing part 98 regulations to permit them to have meaningful and timely input into its development and to provide input on the key regulatory requirements established for these facilities. A summary of these consultations is provided in section VIII.F. of the preamble to the final rule published on October 30, 2009 (74 FR 52620), section V.F. of the preamble to the final rule published on July 12, 2010 (75 FR 39736), section IV.F. of the preamble to the re-proposal of subpart W (Petroleum and Natural Gas Systems) published on April 12, 2010 (75 FR 18608), and section IV.F. of the preambles to the final rules published on December 1, 2010 (75 FR 74774 and 75 FR 75076). As described in this section, the final rule does not significantly revise the established regulatory requirements and will not substantially change the equipment, monitoring, or reporting activities conducted by these facilities, or result in other substantial impacts for tribal facilities. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks The EPA interprets Executive Order 13045 as applying only 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 51 EPA Policy on Consultation and Coordination with Indian Tribes, May 4, 2011. Available at: www.epa.gov/sites/default/files/2013-08/ documents/cons-and-coord-with-indian-tribespolicy.pdf. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 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. lotter on DSK11XQN23PROD with RULES2 H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer and Advancement Act and 1 CFR Part 51 This action involves technical standards. The EPA has decided to incorporate by reference several standards in establishing monitoring requirements in these final amendments. The EPA currently allows for the use of the Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA–430–R– 10–003, March 2010 (EPA 430–R–10– 003) in other sections of part 98, including subpart I (Electronics Manufacturing). The EPA is adding the use of EPA 430–R–10–003 to subpart I for use for measurement of DREs from abatement systems, including HC fuel CECS, purchased and installed on or after January 1, 2025. EPA 430–R–10– 003 provides methods for measuring abatement system inlet and outlet mass or volume flows for single or multichamber process tools, accounting for dilution. Anyone may access EPA 430– R–10–003 at https://www.epa.gov/sites/ default/files/2016-02/documents/dre_ protocol.pdf. This standard is available to everyone at no cost; therefore, the method is reasonably available for reporters. The EPA is allowing the use of an alternate method, ASTM E415–17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (2017), for the purposes of subpart Q (Iron and Steel Production) monitoring and reporting. The EPA currently allows for the use of ASTM E415–17 in other sections of part 98, including under 40 CFR 98.144(b) where it can be used to determine the composition of coal, coke, and solid residues from combustion processes by glass production facilities. Therefore, the EPA is allowing ASTM E415–17 to be used in subpart Q. ASTM E415–17 uses spark atomic emission vacuum spectrometry to determine 21 alloying and residual elements in carbon and low-alloy steels. The method is designed for chill-cast, rolled, and VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 forged specimens. (See the end of section VIII.I. of this preamble for availability information.) The EPA is adding new subpart VV to part 98 for certain EOR operations that choose to use the co-published ISO/CSA standard designated as CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation and geological storage— Carbon dioxide storage using enhanced oil recovery (CO2–EOR), as a means of quantifying geologic sequestration. The EPA is also clarifying in subpart UU at 40 CFR 98.470(c) and subpart VV at 40 CFR 98.481 that CO2–EOR projects previously reporting under subpart UU that begin using CSA/ANSI ISO 27916:19 part-way through a reporting year must report under subpart UU for the portion of the year before CSA/ANSI ISO 27916:19 was used and report under subpart VV for the portion of the year once CSA/ANSI ISO 27916:19 began to be used and thereafter. CSA/ ANSI ISO 27916:19 identifies and quantifies CO2 losses (including fugitive emissions) and quantifies the amount of CO2 stored in association with the CO2EOR project. It also shows how allocation rations can be used to account for the anthropogenic portion of the stored CO2. Anyone may access the standard on the CSA group website (www.csagroup.org/store) for additional information. The standard is available to everyone at a cost determined by CSA Group ($225). CSA Group also offers memberships or subscriptions for reduced costs. Because the use of the standard is optional, the cost of obtaining this standard is not a significant financial burden. The EPA is adding new subpart WW to part 98 (Coke Calciners) and is allowing the use of any one of the following standards for coke calcining facilities: (1) ASTM D3176–15 Standard Practice for Ultimate Analysis of Coal and Coke, (2) ASTM D5291–16 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, and (3) ASTM D5373–21 Standard Test Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke. These methods are used to determine the carbon content of petroleum coke. The EPA currently allows for the use of an earlier version of these standard methods for the instrumental determination of carbon content in laboratory samples of petroleum coke in other sections of part 98, including the use of ASTM D3176– 89, ASTM D5291–02, and ASTM D5373–08 in 40 CFR 98.244(b) (subpart X—Petrochemical Production) and 40 PO 00000 Frm 00087 Fmt 4701 Sfmt 4700 31887 CFR 98.254(i) (subpart Y—Petroleum Refineries). The EPA is allowing the use of the updated versions of these standards (ASTM D3176–15, ASTM D5291–16, and ASTM D5373–21) to determine the carbon content of petroleum coke for subpart WW (Coke Calciners). ASTM D3176–15 provides direction for a convenient and uniform system of analysis of the ash content and the content of organic constituents in coal and coke; this method references the appropriate ASTM methods for sample collection, preparation, content determination, and provides consistency measures for calculation and reporting of results. ASTM D5291– 16 provides a series of test methods for the simultaneous instrumental determination of carbon, hydrogen, and nitrogen in petroleum products and lubricants such as crude oils, fuel oils, additives, and residues; the method allows for a variety of instrumental components and configurations for measurement and calculation of concentrations of carbon, hydrogen, and nitrogen. ASTM D5373–21 provides a methodology for the determination of carbon, hydrogen, and nitrogen content in coal or carbon in coke using furnace combustion and instrument detection systems; the method addresses the determination of carbon in the range of 54.9 percent m/m to 84.7 percent m/m, hydrogen in the range of 3.26 percent m/m to 5.08 percent m/m, and nitrogen in the range of 0.57 percent m/m to 1.76 percent m/m in the analysis sample of coal. (See the end of section VIII.I. of this preamble for availability information.) We are allowing the use of the following standard for coke calciners subject to subpart WW: NIST HB 44– 2023, NIST Handbook 44: Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, 2023 edition. The EPA currently allows for the use of an earlier version of the proposed standard method, Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009), for the calibration and maintenance of instruments used for weighing of mass of samples of petroleum coke in other sections of part 98, including 40 CFR 98.244(b) (subpart X). The EPA is allowing the use of the updated version of this standard, NIST HB 44–2023: Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, 2023 edition, for performing mass measurements of petroleum coke for subpart WW (Coke Calciners). This E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31888 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations standard includes specifications on design of equipment, tolerances to limit the allowable error, sensitivity requirements, and other technical requirements for weighing and measuring devices. Anyone may access the standards on the NIST website (www.nist.gov/) for additional information. These standards are available to everyone at no cost; therefore the methods are reasonably available for reporters. The EPA is adding new subpart XX to part 98 (Calcium Carbide Production) and is allowing the use of one of the following standards for calcium carbide production facilities: (1) ASTM D5373– 08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, or (2) ASTM C25–06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime. ASTM D5373–08 addresses the determination of carbon in the range of 54.9 percent m/m to 84.7 percent m/m, hydrogen in the range of 3.25 percent m/m to 5.10 percent m/m, and nitrogen in the range of 0.57 percent m/m to 1.80 percent m/m in the analysis sample of coal. The EPA currently allows for the use of ASTM D5373–08 in other sections of part 98, including in 40 CFR 98.244(b) (subpart X— Petrochemical Production), 40 CFR 98.284(c) (subpart BB—Silicon Carbide Production), and 40 CFR 98.314(c) (subpart EE—Titanium Production) for the instrumental determination of carbon content in laboratory samples. Therefore, we are allowing the use of ASTM D5373–08 for determination of carbon content of materials consumed, used, or produced at calcium carbide facilities. The EPA currently allows for the use of ASTM C25–06 in other sections of part 98, including in 40 CFR 98.194(c) (subpart S—Lime Production) for chemical composition analysis of lime products and calcined byproducts and in 40 CFR 98.184(b) (subpart R—Lead Production) for analysis of flux materials such as limestone or dolomite. ASTM C25–06 addresses the chemical analysis of high-calcium and dolomitic limestone, quicklime, and hydrated lime. We are allowing the use of ASTM C25–06 for determination of carbon content of materials consumed, used, or produced at calcium carbide facilities, including analysis of materials such as limestone or dolomite. Anyone may access the standards on the ASTM website (www.astm.org/) for additional information. These standards are available to everyone at a cost determined by the ASTM (between $48 and $92 per standard). The ASTM also VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 offers memberships or subscriptions that allow unlimited access to their methods. The cost of obtaining these methods is not a significant financial burden, making the methods reasonably available for reporters. The EPA will also make a copy of these documents available in hard copy at the appropriate EPA office (see the FOR FURTHER INFORMATION CONTACT section of this preamble for more information) for review purposes only. The EPA is not requiring the use of specific consensus standards for new subparts YY (Caprolactam, Glyoxal, and Glyoxylic Acid Production) or ZZ (Ceramics Manufacturing), or for other amendments to part 98. The following standards appear in the amendatory text of this document and were previously approved for the locations in which they appear: • ASTM D3176–89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke; • ASTM D5291–02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants; • ASTM E1019–08 Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques; • Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009); • ASTM D6866–16 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis). • ASTM D7459–08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources. • ASTM D2505–88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography. • T650 om–05 Solids Content of Black Liquor, TAPPI. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations The EPA believes that this type of action does not directly concern human health or environmental conditions and therefore cannot be evaluated with respect to potentially disproportionate and adverse effects on communities with environmental justice concerns. PO 00000 Frm 00088 Fmt 4701 Sfmt 4700 This action does not affect the level of protection provided to human health or the environment, but instead, addresses information collection and reporting procedures. Although this action does not concern human health or environmental conditions, the EPA identified and addressed environmental justice concerns by promoting meaningful engagement from communities in developing the action, and in developing requirements that improve the quality of data available to communities. The EPA provided multiple public comment periods on the proposed 2022 Data Quality Improvements Proposal (from June 21, 2022 to October 6, 2022) and the 2023 Supplemental Proposal (May 22, 2023 to July 21, 2023), and provided opportunities for virtual public hearing(s) for members of the public to share information or concerns and participate in the decision-making process. Further, the EPA has developed improvements to the GHGRP that benefit the public by increasing the completeness and accuracy of facility emissions data. The data collected through this action will provide an important data resource for communities and the public to understand GHG emissions, including requiring reporting of GHG data from additional emission sources and providing more comprehensive coverage of U.S. GHG emissions. Transparent, standardized public data on emissions allows for accountability of polluters to the public who bear the cost of the pollution. Although the emissions reported to the EPA by reporting facilities are global pollutants, many of these facilities also release pollutants that have a more direct and local impact in the surrounding communities. GHGRP data are easily accessible to the public via the EPA’s online data publication tool (FLIGHT), which allows users to view and sort GHG data from over 8,000 entities in a variety of ways including by location, industrial sector, type of GHG emitted, and provides supplementary demographic data that may be useful to communities with environmental justice concerns. As described further in sections II. and III. of this preamble, the final rule improves the quality and transparency of this reported data to affected communities and enables members of the public to have access to and improve their understanding of GHG emissions and pollutants that may impact them. K. Congressional Review Act (CRA) This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 Comptroller General of the United States. This action is not a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). L. Judicial Review Under CAA section 307(b)(1), any petition for review of this final rule must be filed in the U.S. Court of Appeals for the District of Columbia Circuit by June 24, 2024. This final rule establishes requirements applicable to owners and operators of facilities and suppliers in many industry source categories located across the United States that are subject to 40 CFR part 98 and therefore is ‘‘nationally applicable’’ within the meaning of CAA section 307(b)(1). Further, pursuant to CAA section 307(d)(1)(V), the Administrator has determined that this rule is subject to the provisions of CAA section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to ‘‘such other actions as the Administrator may determine’’). Under CAA section 307(d)(7)(B), only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. CAA section 307(d)(7)(B) also provides a mechanism for the EPA to convene a proceeding for reconsideration, ‘‘[i]f the person raising an objection can demonstrate to EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.’’ Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, Environmental Protection Agency, Room 3000, William Jefferson Clinton Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with an electronic copy to the person listed in FOR FURTHER INFORMATION CONTACT, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20004. Note that under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements. List of Subjects 40 CFR Part 9 Environmental protection, Administrative practice and procedure, VerDate Sep<11>2014 20:16 Apr 24, 2024 Jkt 262001 Reporting and recordkeeping requirements. 31889 (f) * * * (1) Calculate the mass in metric tons per year of CO2, N2O, each fluorinated 40 CFR Part 98 GHG, and each fluorinated heat transfer Environmental protection, fluid that is imported and the mass in Greenhouse gases, Incorporation by metric tons per year of CO2, N2O, each reference, Reporting and recordkeeping fluorinated GHG, and each fluorinated requirements, Suppliers. heat transfer fluid that is exported Michael S. Regan, during the year. Administrator. * * * * * For the reasons stated in the (i) * * * preamble, the Environmental Protection (1) If reported CO2e emissions, Agency amends title 40, chapter I, of the calculated in accordance with Code of Federal Regulations as follows: § 98.3(c)(4)(i), are less than 25,000 PART 9—OMB APPROVALS UNDER metric tons per year for five consecutive THE PAPERWORK REDUCTION ACT years, then the owner or operator may discontinue complying with this part ■ 1. The authority citation for part 9 provided that the owner or operator continues to read as follows: submits a notification to the Authority: 7 U.S.C. 135 et seq., 136–136y; Administrator that announces the 15 U.S.C. 2001, 2003, 2005, 2006, 2601–2671; cessation of reporting and explains the 21 U.S.C. 331j, 346a, 31 U.S.C. 9701; 33 reasons for the reduction in emissions. U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, The notification shall be submitted no 1321, 1326, 1330, 1342, 1344, 1345(d) and later than March 31 of the year (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971–1975 Comp. p. 973; 42 U.S.C. 241, immediately following the fifth 242b, 243, 246, 300f, 300g, 300g–1, 300g–2, consecutive year of emissions less than 300g–3, 300g–4, 300g–5, 300g–6, 300j–1, 25,000 tons CO2e per year. The owner 300j–2, 300j–3, 300j–4, 300j–9, 1857 et seq., or operator must maintain the 6901–6992k, 7401–7671q, 7542, 9601–9657, corresponding records required under 11023, 11048. § 98.3(g) for each of the five consecutive ■ 2. Amend § 9.1 by adding an years prior to notification of undesignated center heading and an discontinuation of reporting and retain entry for ‘‘98.1–98.528’’ in numerical such records for three years following order to read as follows: the year that reporting was § 9.1 OMB approvals under the Paperwork discontinued. The owner or operator Reduction Act. must resume reporting if annual CO2e * * * * * emissions, calculated in accordance with paragraph (b)(4) of this section, in OMB control any future calendar year increase to 40 CFR citation No. 25,000 metric tons per year or more. (2) If reported CO2e emissions, * * * * * calculated in accordance with § 98.3(c)(4)(i), were less than 15,000 Mandatory Greenhouse Gas Reporting metric tons per year for three 98.1–98.528 .......................... 2060–0629 consecutive years, then the owner or operator may discontinue complying * * * * * with this part provided that the owner or operator submits a notification to the Administrator that announces the PART 98—MANDATORY cessation of reporting and explains the GREENHOUSE GAS REPORTING reasons for the reduction in emissions. ■ 3. The authority citation for part 98 The notification shall be submitted no continues to read as follows: later than March 31 of the year Authority: 42 U.S.C. 7401–7671q. immediately following the third consecutive year of emissions less than Subpart A—General Provision 15,000 tons CO2e per year. The owner or operator must maintain the ■ 4. Amend § 98.2 by: corresponding records required under ■ a. Revising paragraphs (f)(1) and (i)(1) § 98.3(g) for each of the three and (2); and consecutive years and retain such ■ b. Adding paragraph (k). The revisions and addition read as records for three years prior to follows: notification of discontinuation of reporting following the year that § 98.2 Who must report? reporting was discontinued. The owner * * * * * PO 00000 Frm 00089 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31890 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations or operator must resume reporting if annual CO2e emissions, calculated in accordance with paragraph (b)(4) of this section, in any future calendar year increase to 25,000 metric tons per year or more. * * * * * (k) To calculate GHG quantities for comparison to the 25,000 metric ton CO2e per year threshold under paragraph (a)(4) of this section for facilities that destroy fluorinated GHGs or fluorinated heat transfer fluids, the owner or operator shall calculate the mass in metric tons per year of CO2e destroyed as described in paragraphs (k)(1) through (3) of this section. (1) Calculate the mass in metric tons per year of each fluorinated GHG or fluorinated heat transfer fluid that is destroyed during the year. (2) Convert the mass of each destroyed fluorinated GHG or fluorinated heat transfer fluid from paragraph (k)(1) of this section to metric tons of CO2e using equation A–1 to this section. (3) Sum the total annual metric tons of CO2e in paragraph (k)(2) of this section for all destroyed fluorinated GHGs and destroyed fluorinated heat transfer fluids. ■ 5. Amend § 98.3 by: ■ a. Revising paragraphs (b)(2), (h)(4), and (k)(1) through (3); and ■ b. Revising and republishing paragraph (l). The revisions and republication read as follows: § 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part? lotter on DSK11XQN23PROD with RULES2 * * * * * (b) * * * (2) For a new facility or supplier that begins operation on or after January 1, 2010 and becomes subject to the rule in the year that it becomes operational, report emissions starting the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31. * * * * * (h) * * * (4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner or operator, the Administrator may provide reasonable extensions of the 45-day period for submission of the revised report or information under paragraphs (h)(1) and (2) of this section. If the Administrator receives a request for extension of the 45-day period, by email to an address VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 prescribed by the Administrator prior to the expiration of the 45-day period, the extension request is deemed to be automatically granted for 30 days. The Administrator may grant an additional extension beyond the automatic 30-day extension if the owner or operator submits a request for an additional extension and the request is received by the Administrator prior to the expiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report or information under paragraphs (h)(1) and (2) of this section within 75 days. The Administrator will approve the extension request if the request demonstrates to the Administrator’s satisfaction that it is not practicable to collect and process the data needed to resolve potential reporting errors identified pursuant to paragraph (h)(1) or (2) of this section within 75 days. The Administrator will only approve an extension request for a total of 180 days after the initial notification of a substantive error. * * * * * (k) * * * (1) A facility or supplier that first becomes subject to part 98 due to a change in the GWP for one or more compounds in table A–1 to this subpart, Global Warming Potentials, is not required to submit an annual GHG report for the reporting year during which the change in GWPs is published in the Federal Register as a final rulemaking. (2) A facility or supplier that was already subject to one or more subparts of this part but becomes subject to one or more additional subparts due to a change in the GWP for one or more compounds in table A–1 to this subpart, is not required to include those subparts to which the facility is subject only due to the change in the GWP in the annual GHG report submitted for the reporting year during which the change in GWPs is published in the Federal Register as a final rulemaking. (3) Starting on January 1 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking, facilities or suppliers identified in paragraph (k)(1) or (2) of this section must start monitoring and collecting GHG data in compliance with the applicable subparts of part 98 to which the facility is subject due to the change in the GWP for the annual greenhouse gas report for that reporting year, which is due by March 31 of the following calendar year. * * * * * (l) Special provision for best available monitoring methods in 2014 and PO 00000 Frm 00090 Fmt 4701 Sfmt 4700 subsequent years. This paragraph (l) applies to owners or operators of facilities or suppliers that first become subject to any subpart of this part due to an amendment to table A–1 to this subpart, Global Warming Potentials. (1) Best available monitoring methods. From January 1 to March 31 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking, owners or operators subject to this paragraph (l) may use best available monitoring methods for any parameter (e.g., fuel use, feedstock rates) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the ‘‘Calculating GHG Emissions’’ sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking. Starting no later than April 1 of the year after the year during which the change in GWPs is published, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraph (l)(2) of this section. Best available monitoring methods means any of the following methods: (i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. (2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking. (i) Timing of request. The extension request must be submitted to EPA no later than January 31 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking. (ii) Content of request. Requests must contain the following information: (A) A list of specific items of monitoring instrumentation for which the request is being made and the locations where each piece of E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations monitoring instrumentation will be installed. (B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed. (C) A description of the reasons that the needed equipment could not be obtained and installed before April 1 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking. (D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery. (E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between November 29 of the year during which the change in GWPs is published in the Federal Register as a final rulemaking and April 1 of the year after the year during which the change in GWPs is published, include a justification of why the equipment could not be obtained and installed during that shutdown. (F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating. (iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1 of the year after the year during which the change in GWPs is published in the Federal Register as a final rulemaking. The use of best available methods under this paragraph (l) will not be approved VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 beyond December 31 of the year after the year during which the change in GWPs is published. ■ 6. Amend § 98.5 by revising paragraph (b) to read as follows: § 98.5 How is the report submitted? * * * * * (b) For reporting year 2014 and thereafter, unless a later year is specified in the applicable recordkeeping section, you must enter into verification software specified by the Administrator the data specified as verification software records in each applicable recordkeeping section. For each data element entered into the verification software, if the software produces a warning message for the data value and you elect not to revise the data value, you may provide an explanation in the verification software of why the data value is not being revised. ■ 7. Amend § 98.6 by: ■ a. Revising the definitions ‘‘ASTM’’, ‘‘Bulk’’, and ‘‘Carbon dioxide stream’’; ■ b. Adding the definitions ‘‘Cyclic’’ and ‘‘Direct air capture (DAC)’’ in alphabetical order; ■ c. Removing the definition ‘‘Fluorinated greenhouse gas’’; ■ d. Adding the definition ‘‘Fluorinated greenhouse gas (GHG)’’ in alphabetical order; ■ e. Revising the definition ‘‘Fluorinated greenhouse gas (GHG) group’’; ■ f. Adding the definition ‘‘Fluorinated heat transfer fluids’’ in alphabetic order; ■ g. Revising the definition ‘‘Greenhouse gas or GHG’’; ■ h. Removing the definition ‘‘Other fluorinated GHGs’’; ■ i. Revising the definition ‘‘Process vent’’; and ■ j. Adding definitions ‘‘Remaining fluorinated GHGs’’, ‘‘Saturated chlorofluorocarbons (CFCs)’’, ‘‘Unsaturated bromochlorofluorocarbons (BCFCs)’’, ‘‘Unsaturated bromofluorocarbons (BFCs)’’, ‘‘Unsaturated chlorofluorocarbons (CFCs)’’, ‘‘Unsaturated hydrobromochlorofluorocarbons (HBCFCs)’’, and ‘‘Unsaturated hydrobromofluorocarbons (HBFCs)’’ in alphabetic order. The revisions and additions read as follows: § 98.6 Definitions. * * * * * ASTM means ASTM, International. * * * * * Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means a transfer of gas in any amount that is in PO 00000 Frm 00091 Fmt 4701 Sfmt 4700 31891 a container for the transportation or storage of that substance such as cylinders, drums, ISO tanks, and small cans. An industrial gas or CO2 that must first be transferred from a container to another container, vessel, or piece of equipment in order to realize its intended use is a bulk substance. An industrial GHG or CO2 that is contained in a manufactured product such as electrical equipment, appliances, aerosol cans, or foams is not a bulk substance. * * * * * Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g., a power plant or other industrial facility), captured from ambient air (e.g., direct air capture), or extracted from a carbon dioxide production well plus incidental associated substances either derived from the source materials and the capture process or extracted with the carbon dioxide. * * * * * Cyclic, in the context of fluorinated GHGs, means a fluorinated GHG in which three or more carbon atoms are connected to form a ring. * * * * * Direct air capture (DAC), with respect to a facility, technology, or system, means that the facility, technology, or system uses carbon capture equipment to capture carbon dioxide directly from the air. Direct air capture does not include any facility, technology, or system that captures carbon dioxide: (1) That is deliberately released from a naturally occurring subsurface spring; or (2) Using natural photosynthesis. * * * * * Fluorinated greenhouse gas (GHG) means sulfur hexafluoride (SF6), nitrogen trifluoride (NF3), and any fluorocarbon except for controlled substances as defined at part 82, subpart A of this subchapter and substances with vapor pressures of less than 1 mm of Hg absolute at 25 degrees C. With these exceptions, ‘‘fluorinated GHG’’ includes but is not limited to any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and any hydrofluoropolyether. Fluorinated greenhouse gas (GHG) group means one of the following sets of fluorinated GHGs: (1) Fully fluorinated GHGs; (2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen bonds; (3) Saturated hydrofluorocarbons with three or more carbon-hydrogen bonds; E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31892 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (4) Saturated hydrofluoroethers and hydrochlorofluoroethers with one carbon-hydrogen bond; (5) Saturated hydrofluoroethers and hydrochlorofluoroethers with two carbon-hydrogen bonds; (6) Saturated hydrofluoroethers and hydrochlorofluoroethers with three or more carbon-hydrogen bonds; (7) Saturated chlorofluorocarbons (CFCs); (8) Fluorinated formates; (9) Cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons (BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated hydrobromofluorocarbons (HBFCs), unsaturated hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, and unsaturated halogenated esters; (10) Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols; (11) Fluorinated aldehydes, fluorinated ketones and non-cyclic forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers, and unsaturated halogenated esters; (12) Fluorotelomer alcohols; (13) Fluorinated GHGs with carboniodine bonds; or (14) Remaining fluorinated GHGs. Fluorinated heat transfer fluids means fluorinated GHGs used for temperature control, device testing, cleaning substrate surfaces and other parts, other solvent applications, and soldering in certain types of electronics manufacturing production processes and in other industries. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants in electronics manufacturing. For fluorinated heat transfer fluids, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of ‘‘fluorinated greenhouse gas’’ in this section shall not apply. Fluorinated heat transfer fluids include, but are not limited to, perfluoropolyethers (including PFPMIE), perfluoroalkylamines, perfluoroalkylmorpholines, perfluoroalkanes, perfluoroethers, perfluorocyclic ethers, and hydrofluoroethers. Fluorinated heat transfer fluids include HFC–43–10meee VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 but do not include other hydrofluorocarbons. * * * * * Greenhouse gas or GHG means carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), and fluorinated greenhouse gases (GHGs) as defined in this section. * * * * * Process vent means a gas stream that: Is discharged through a conveyance to the atmosphere either directly or after passing through a control device; originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces, and separation equipment for products and recovered byproducts); and contains or has the potential to contain GHG that is generated in the process. Process vent does not include safety device discharges, equipment leaks, gas streams routed to a fuel gas system or to a flare, discharges from storage tanks. * * * * * Remaining fluorinated GHGs means fluorinated GHGs that are none of the following: (1) Fully fluorinated GHGs; (2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen bonds; (3) Saturated hydrofluorocarbons with three or more carbon-hydrogen bonds; (4) Saturated hydrofluoroethers and hydrochlorofluoroethers with one carbon-hydrogen bond; (5) Saturated hydrofluoroethers and hydrochlorofluoroethers with two carbon-hydrogen bonds; (6) Saturated hydrofluoroethers and hydrochlorofluoroethers with three or more carbon-hydrogen bonds; (7) Saturated chlorofluorocarbons (CFCs); (8) Fluorinated formates; (9) Cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons (BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated hydrobromofluorocarbons (HBFCs), unsaturated hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, and unsaturated halogenated esters; (10) Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols; (11) Fluorinated aldehydes, fluorinated ketones and non-cyclic forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, unsaturated PO 00000 Frm 00092 Fmt 4701 Sfmt 4700 HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers, and unsaturated halogenated esters; (12) Fluorotelomer alcohols; or (13) fluorinated GHGs with carboniodine bonds. * * * * * Saturated chlorofluorocarbons (CFCs) means fluorinated GHGs that contain only chlorine, fluorine, and carbon and that contain only single bonds. * * * * * Unsaturated bromochlorofluorocarbons (BCFCs) means fluorinated GHGs that contain only bromine, chlorine, fluorine, and carbon and that contain one or more bonds that are not single bonds. Unsaturated bromofluorocarbons (BFCs) means fluorinated GHGs that contain only bromine, fluorine, and carbon and that contain one or more bonds that are not single bonds. Unsaturated chlorofluorocarbons (CFCs) means fluorinated GHGs that contain only chlorine, fluorine, and carbon and that contain one or more bonds that are not single bonds. * * * * * Unsaturated hydrobromochlorofluorocarbons (HBCFCs) means fluorinated GHGs that contain only hydrogen, bromine, chlorine, fluorine, and carbon and that contain one or more bonds that are not single bonds. Unsaturated hydrobromofluorocarbons (HBFCs) means fluorinated GHGs that contain only hydrogen, bromine, fluorine, and carbon and that contain one or more bonds that are not single bonds. * * * * * ■ 8. Amend § 98.7 by: ■ a. Revising the introductory text; ■ b. Redesignating paragraphs (c) through (e) as paragraphs (b) through (d); ■ c. Revising newly redesignated paragraph (d); ■ d. Adding new paragraph (e); and ■ e. Revising paragraphs (i) and (m)(3). The revisions and addition read as follows: § 98.7 What standardized methods are incorporated by reference into this part? Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that specified in this section, the EPA must publish a document in the Federal Register and the material must be available to the public. All approved incorporation by reference (IBR) material is available for inspection at the EPA and at the National Archives E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations and Records Administration (NARA). Contact EPA at: EPA Docket Center, Public Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. NW, Washington, DC; phone: 202–566–1744; email: Docket-customerservice@epa.gov; website: www.epa.gov/dockets/epadocket-center-reading-room. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ ibr-locations or email fr.inspection@ nara.gov. The material may be obtained from the following sources: * * * * * (d) ASTM International (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959; (800) 262–1373; www.astm.org. (1) ASTM C25–06, Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, approved February 15, 2006; IBR approved for §§ 98.114(b); 98.174(b); 98.184(b); 98.194(c); 98.334(b); and 98.504(b). (2) ASTM C114–09, Standard Test Methods for Chemical Analysis of Hydraulic Cement; IBR approved for § 98.84(a) through (c). (3) ASTM D235–02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent); IBR approved for § 98.6. (4) ASTM D240–02 (Reapproved 2007), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter; IBR approved for § 98.254(e). (5) ASTM D388–05, Standard Classification of Coals by Rank; IBR approved for § 98.6. (6) ASTM D910–07a, Standard Specification for Aviation Gasolines; IBR approved for § 98.6. (7) ASTM D1826–94 (Reapproved 2003), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter; IBR approved for § 98.254(e). (8) ASTM D1836–07, Standard Specification for Commercial Hexanes; IBR approved for § 98.6. (9) ASTM D1941–91 (Reapproved 2007), Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007; IBR approved for § 98.354(d). (10) ASTM D1945–03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; IBR approved for §§ 98.74(c); 98.164(b); 98.244(b); 98.254(d); 98.324(d); 98.344(b); 98.354(g). (11) ASTM D1946–90 (Reapproved 2006), Standard Practice for Analysis of VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Reformed Gas by Gas Chromatography; IBR approved for §§ 98.74(c); 98.164(b); 98.254(d); 98.324(d); 98.344(b); 98.354(g); 98.364(c). (12) ASTM D2013–07, Standard Practice for Preparing Coal Samples for Analysis; IBR approved for § 98.164(b). (13) ASTM D2234/D2234M–07, Standard Practice for Collection of a Gross Sample of Coal; IBR approved for § 98.164(b). (14) ASTM D2502–04, Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils From Viscosity Measurements; IBR approved for § 98.74(c). (15) ASTM D2503–92 (Reapproved 2007), Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure; IBR approved for §§ 98.74(c); 98.254(d)(6). (16) ASTM D2505–88 (Reapproved 2004)e1, Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography; IBR approved for § 98.244(b). (17) ASTM D2593–93 (Reapproved 2009), Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, approved July 1, 2009; IBR approved for § 98.244(b). (18) ASTM D2597–94 (Reapproved 2004), Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography; IBR approved for § 98.164(b). (19) ASTM D2879–97 (Reapproved 2007), Standard Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope (ASTM D2879), approved May 1, 2007; IBR approved for § 98.128. (20) ASTM D3176–15, Standard Practice for Ultimate Analysis of Coal and Coke, approved January 1, 2015; IBR approved for § 98.494(c). (21) ASTM D3176–89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke; IBR approved for §§ 98.74(c); 98.164(b); 98.244(b); 98.284(c) and (d); 98.314(c), (d), and (f). (22) ASTM D3238–95 (Reapproved 2005), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method; IBR approved for §§ 98.74(c); 98.164(b). (23) ASTM D3588–98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and PO 00000 Frm 00093 Fmt 4701 Sfmt 4700 31893 Relative Density of Gaseous Fuels; IBR approved for § 98.254(e). (24) ASTM D3682–01 (Reapproved 2006), Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes; IBR approved for § 98.144(b). (25) ASTM D4057–06, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; IBR approved for § 98.164(b). (26) ASTM D4177–95 (Reapproved 2005), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; IBR approved for § 98.164(b). (27) ASTM D4809–06, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method); IBR approved for § 98.254(e). (28) ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; IBR approved for §§ 98.254(e); 98.324(d). (29) ASTM D5291–02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants; IBR approved for §§ 98.74(c); 98.164(b); 98.244(b). (30) ASTM D5291–16, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, approved October 1, 2016; IBR approved for § 98.494(c). (31) ASTM D5373–08, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, approved February 1, 2008; IBR approved for §§ 98.74(c); 98.114(b); 98.164(b); 98.174(b); 98.184(b); 98.244(b); 98.274(b); 98.284(c) and (d); 98.314(c), (d), and (f); 98.334(b); 98.504(b). (32) ASTM D5373–21, Standard Test Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke, approved April 1, 2021; IBR approved for § 98.494(c). (33) ASTM D5614–94 (Reapproved 2008), Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008; IBR approved for § 98.354(d). (34) ASTM D6060–96 (Reapproved 2001), Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph; IBR approved for § 98.244(b). (35) ASTM D6348–03, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared E:\FR\FM\25APR2.SGM 25APR2 31894 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (FTIR) Spectroscopy; IBR approved for § 98.54(b); table I–9 to subpart I of this part; §§ 98.224(b); 98.414(n). (36) ASTM D6349–09, Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma—Atomic Emission Spectrometry; IBR approved for § 98.144(b). (37) ASTM D6609–08, Standard Guide for Part-Stream Sampling of Coal; IBR approved for § 98.164(b). (38) ASTM D6751–08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels; IBR approved for § 98.6. (39) ASTM D6866–16, Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, approved June 1, 2016; IBR approved for §§ 98.34(d) and (e); 98.36(e). (40) ASTM D6883–04, Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles; IBR approved for § 98.164(b). (41) ASTM D7359–08, Standard Test Method for Total Fluorine, Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved October 15, 2008; IBR approved for § 98.124(e)(2). (42) ASTM D7430–08ae1, Standard Practice for Mechanical Sampling of Coal; IBR approved for § 98.164(b). (43) ASTM D7459–08, Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources; IBR approved for §§ 98.34(d) and (e); 98.36(e). (44) ASTM D7633–10, Standard Test Method for Carbon Black—Carbon Content, approved May 15, 2010; IBR approved for § 98.244(b). (45) ASTM E359–00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate); IBR approved for § 98.294(a) and (b). (46) ASTM E415–17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry, approved May 15, 2017; IBR approved for § 98.174(b). (47) ASTM E1019–08, Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques; IBR approved for § 98.174(b). (48) ASTM E1915–07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry; IBR approved for § 98.174(b). (49) ASTM E1941–04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys; IBR approved for §§ 98.114(b); 98.184(b); 98.334(b). (50) ASTM UOP539–97, Refinery Gas Analysis by Gas Chromatography; IBR approved for §§ 98.164(b); 98.244(b); 98.254(d); 98.324(d); 98.344(b); 98.354(g). (e) CSA Group (CSA), 178 Rexdale Boulevard, Toronto, Ontario Canada M9W 183; (800) 463–6727; https:// shop.csa.ca. (1) CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation and geological storage—Carbon dioxide storage using enhanced oil recovery (CO2–EOR), approved August 30, 2019; IBR approved for §§ 98.470(c); 98.480(a); 98.481(a) through (c); 98.482; 98.483; 98.484; 98.485; 98.486(g); 98.487; 98.488(a)(5); 98.489. Note 1 to paragraph (e)(1): This standard is also available from ISO as ISO 27916:2019(E). (2) [Reserved] * * * * (i) National Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 20899– 1070, (800) 877–8339, www.nist.gov/. (1) NIST HB 44–2023: Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, 2023 edition, approved November 18, 2022; IBR approved for § 98.494(b). (2) Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009); IBR approved for §§ 98.244(b); 98.344(a). * * * * * (m) * * * (3) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA–430–R– 10–003, March 2010 (EPA 430–R–10– 003), approved March 2010; IBR approved for §§ 98.94(e); 98.94(f) and (g); 98.97(b) and (d); 98.98; appendix A to subpart I of this part; §§ 98.124(e); 98.414(n). (Also available from: www.epa.gov/sites/default/files/201602/documents/dre_protocol.pdf.) * * * * * ■ 9. Revise table A–1 to subpart A to read as follows: * TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS, 100-YEAR TIME HORIZON Name CAS No. Chemical formula Global warming potential (100 yr.) Chemical-Specific GWPs Carbon dioxide ...................................................................... Methane ................................................................................. Nitrous oxide .......................................................................... 124–38–9 74–82–8 10024–97–2 CO2 ................................................................ CH4 ................................................................ N2O ................................................................ 1 a d 28 a d 265 lotter on DSK11XQN23PROD with RULES2 Fully Fluorinated GHGs Sulfur hexafluoride ................................................................. Trifluoromethyl sulphur pentafluoride .................................... Nitrogen trifluoride ................................................................. PFC–14 (Perfluoromethane) ................................................. PFC–116 (Perfluoroethane) .................................................. PFC–218 (Perfluoropropane) ................................................ Perfluorocyclopropane ........................................................... PFC–3–1–10 (Perfluorobutane) ............................................ PFC–318 (Perfluorocyclobutane) .......................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00094 2551–62–4 373–80–8 7783–54–2 75–73–0 76–16–4 76–19–7 931–91–9 355–25–9 115–25–3 Fmt 4701 Sfmt 4700 SF6 ................................................................. SF5CF3 .......................................................... NF3 ................................................................ CF4 ................................................................ C2F6 ............................................................... C3F8 ............................................................... c-C3F6 ............................................................ C4F10 ............................................................. c-C4F8 ............................................................ E:\FR\FM\25APR2.SGM 25APR2 a d 23,500 d 17,400 d 16,100 a d 6,630 a d 11,100 a d 8,900 d 9,200 a d 9,200 a d 9,540 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31895 TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS, 100-YEAR TIME HORIZON—Continued Name CAS No. Perfluorotetrahydrofuran ........................................................ PFC–4–1–12 (Perfluoropentane) .......................................... PFC–5–1–14 (Perfluorohexane, FC–72) ............................... PFC–6–1–12 .......................................................................... PFC–7–1–18 .......................................................................... PFC–9–1–18 .......................................................................... PFPMIE (HT–70) ................................................................... Perfluorodecalin (cis) ............................................................. Perfluorodecalin (trans) ......................................................... Perfluorotriethylamine ............................................................ Perfluorotripropylamine .......................................................... Perfluorotributylamine ............................................................ Perfluorotripentylamine .......................................................... 773–14–8 678–26–2 355–42–0 335–57–9 307–34–6 306–94–5 NA 60433–11–6 60433–12–7 359–70–6 338–83–0 311–89–7 338–84–1 Chemical formula c-C4F8O ......................................................... C5F12 ............................................................. C6F14 ............................................................. C7F16; CF3(CF2)5CF3 .................................... C8F18; CF3(CF2)6CF3 .................................... C10F18 ............................................................ CF3OCF(CF3)CF2OCF2OCF3 ....................... Z-C10F18 ........................................................ E-C10F18 ........................................................ N(C2F5)3 ........................................................ N(CF2CF2CF3)3 ............................................. N(CF2CF2CF2CF3)3 ....................................... N(CF2CF2CF2CF2CF3)3 ................................ Global warming potential (100 yr.) e 13,900 a d 8,550 a d 7,910 b 7,820 b 7,620 d 7,190 d 9,710 b d 7,240 b d 6,290 e 10,300 e 9,030 e 8,490 e 7,260 Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds (4s,5s)-1,1,2,2,3,3,4,5-octafluorocyclopentane ..................... HFC–23 ................................................................................. HFC–32 ................................................................................. HFC–125 ............................................................................... HFC–134 ............................................................................... HFC–134a ............................................................................. HFC–227ca ............................................................................ HFC–227ea ........................................................................... HFC–236cb ............................................................................ HFC–236ea ........................................................................... HFC–236fa ............................................................................ HFC–329p ............................................................................. HFC–43–10mee .................................................................... 158389–18–5 75–46–7 75–10–5 354–33–6 359–35–3 811–97–2 2252–84–8 431–89–0 677–56–5 431–63–0 690–39–1 375–17–7 138495–42–8 trans-cyc (-CF2CF2CF2CHFCHF-) ............... CHF3 .............................................................. CH2F2 ............................................................ C2HF5 ............................................................ C2H2F4 ........................................................... CH2FCF3 ....................................................... CF3CF2CHF2 ................................................. C3HF7 ............................................................ CH2FCF2CF3 ................................................. CHF2CHFCF3 ................................................ C3H2F6 ........................................................... CHF2CF2CF2CF3 ........................................... CF3CFHCFHCF2CF3 ..................................... e 258 a d 12,400 a d 677 a d 3,170 a d 1,120 a d 1,300 b 2,640 a d 3,350 d 1,210 d 1,330 a d 8,060 b 2360 a d 1,650 Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds 1,1,2,2,3,3-hexafluorocyclopentane ....................................... 1,1,2,2,3,3,4-heptafluorocyclopentane .................................. HFC–41 ................................................................................. HFC–143 ............................................................................... HFC–143a ............................................................................. HFC–152 ............................................................................... HFC–152a ............................................................................. HFC–161 ............................................................................... HFC–245ca ............................................................................ HFC–245cb ............................................................................ HFC–245ea ........................................................................... HFC–245eb ........................................................................... HFC–245fa ............................................................................ HFC–263fb ............................................................................ HFC–272ca ............................................................................ HFC–365mfc .......................................................................... 123768–18–3 15290–77–4 593–53–3 430–66–0 420–46–2 624–72–6 75–37–6 353–36–6 679–86–7 1814–88–6 24270–66–4 431–31–2 460–73–1 421–07–8 420–45–1 406–58–6 cyc (-CF2CF2CF2CH2CH2-) ........................... cyc (-CF2CF2CF2CHFCH2-) .......................... CH3F .............................................................. C2H3F3 ........................................................... C2H3F3 ........................................................... CH2FCH2F ..................................................... CH3CHF2 ....................................................... CH3CH2F ....................................................... C3H3F5 ........................................................... CF3CF2CH3 ................................................... CHF2CHFCHF2 ............................................. CH2FCHFCF3 ................................................ CHF2CH2CF3 ................................................. CH3CH2CF3 ................................................... CH3CF2CH3 ................................................... CH3CF2CH2CF3 ............................................ e 120 e 231 a d 116 a d 328 a d 4,800 d 16 a d 138 d4 a d 716 b 4,620 b 235 b 290 d 858 b 76 b 144 d 804 Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond HFE–125 ................................................................................ HFE–227ea ............................................................................ HFE–329mcc2 ....................................................................... HFE–329me3 ......................................................................... 1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-propane. 3822–68–2 2356–62–9 134769–21–4 428454–68–6 3330–15–2 CHF2OCF3 ..................................................... CF3CHFOCF3 ................................................ CF3CF2OCF2CHF2 ........................................ CF3CFHCF2OCF3 ......................................... CF3CF2CF2OCHFCF3 ................................... d 12,400 d 6,450 d 3,070 b 4,550 b 6,490 lotter on DSK11XQN23PROD with RULES2 Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds HFE–134 (HG–00) ................................................................. HFE–236ca ............................................................................ HFE–236ca12 (HG–10) ......................................................... HFE–236ea2 (Desflurane) ..................................................... HFE–236fa ............................................................................. HFE–338mcf2 ........................................................................ HFE–338mmz1 ...................................................................... HFE–338pcc13 (HG–01) ....................................................... HFE–43–10pccc (H-Galden 1040x, HG–11) ......................... HCFE–235ca2 (Enflurane) .................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00095 1691–17–4 32778–11–3 78522–47–1 57041–67–5 20193–67–3 156053–88–2 26103–08–2 188690–78–0 E1730133 13838–16–9 Fmt 4701 Sfmt 4700 CHF2OCHF2 .................................................. CHF2OCF2CHF2 ............................................ CHF2OCF2OCHF2 ......................................... CHF2OCHFCF3 ............................................. CF3CH2OCF3 ................................................ CF3CF2OCH2CF3 .......................................... CHF2OCH(CF3)2 ........................................... CHF2OCF2CF2OCHF2 .................................. CHF2OCF2OC2F4OCHF2 .............................. CHF2OCF2CHFCl .......................................... E:\FR\FM\25APR2.SGM 25APR2 d 5,560 b 4,240 d 5,350 d 1,790 d 979 d 929 d 2,620 d 2,910 d 2,820 b 583 31896 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS, 100-YEAR TIME HORIZON—Continued Name CAS No. HCFE–235da2 (Isoflurane) .................................................... HG–02 ................................................................................... HG–03 ................................................................................... HG–20 ................................................................................... HG–21 ................................................................................... HG–30 ................................................................................... 1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,15eicosafluoro-2,5,8,11,14-Pentaoxapentadecane. 1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane ............................ Trifluoro(fluoromethoxy)methane ........................................... Chemical formula 26675–46–7 205367–61–9 173350–37–3 249932–25–0 249932–26–1 188690–77–9 173350–38–4 CHF2OCHClCF3 ............................................ HF2C-(OCF2CF2)2-OCF2H ............................ HF2C-(OCF2CF2)3-OCF2H ............................ HF2C-(OCF2)2-OCF2H .................................. HF2C-OCF2CF2OCF2OCF2O-CF2H .............. HF2C-(OCF2)3-OCF2H .................................. HCF2O(CF2CF2O)4CF2H ............................... 84011–06–3 2261–01–0 CHF2CHFOCF3 ............................................. CH2FOCF3 ..................................................... Global warming potential (100 yr.) d 491 b d 2,730 b d 2,850 b 5,300 b 3,890 b 7,330 b 3,630 b 1,240 b 751 Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds HFE–143a .............................................................................. HFE–245cb2 .......................................................................... HFE–245fa1 ........................................................................... HFE–245fa2 ........................................................................... HFE–254cb1 .......................................................................... HFE–263fb2 ........................................................................... HFE–263m1; R–E–143a ....................................................... HFE–347mcc3 (HFE–7000) .................................................. HFE–347mcf2 ........................................................................ HFE–347mmy1 ...................................................................... HFE–347mmz1 (Sevoflurane) ............................................... HFE–347pcf2 ......................................................................... HFE–356mec3 ....................................................................... HFE–356mff2 ......................................................................... HFE–356mmz1 ...................................................................... HFE–356pcc3 ........................................................................ HFE–356pcf2 ......................................................................... HFE–356pcf3 ......................................................................... HFE–365mcf2 ........................................................................ HFE–365mcf3 ........................................................................ HFE–374pc2 .......................................................................... HFE–449s1 (HFE–7100) Chemical blend ............................. HFE–569sf2 (HFE–7200) Chemical blend ............................ HFE–7300 .............................................................................. HFE–7500 .............................................................................. HG′-01 ................................................................................... HG′-02 ................................................................................... HG′-03 ................................................................................... Difluoro(methoxy)methane .................................................... 2-Chloro-1,1,2-trifluoro-1-methoxyethane .............................. 1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane ........................... 2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-bis[1,2,2,2tetrafluoro-1-(trifluoromethyl)ethyl]-furan. 1-Ethoxy-1,1,2,3,3,3-hexafluoropropane ............................... Fluoro(methoxy)methane ....................................................... 1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3tetrafluoropropyl ether. 1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane ......................... Difluoro(fluoromethoxy)methane ........................................... Fluoro(fluoromethoxy)methane .............................................. 421–14–7 22410–44–2 84011–15–4 1885–48–9 425–88–7 460–43–5 690–22–2 375–03–1 171182–95–9 22052–84–2 28523–86–6 406–78–0 382–34–3 333–36–8 13171–18–1 160620–20–2 50807–77–7 35042–99–0 22052–81–9 378–16–5 512–51–6 163702–07–6 163702–08–7 163702–05–4 163702–06–5 132182–92–4 297730–93–9 73287–23–7 485399–46–0 485399–48–2 359–15–9 425–87–6 22052–86–4 920979–28–8 CH3OCF3 ....................................................... CH3OCF2CF3 ................................................ CHF2CH2OCF3 .............................................. CHF2OCH2CF3 .............................................. CH3OCF2CHF2 .............................................. CF3CH2OCH3 ................................................ CF3OCH2CH3 ................................................ CH3OCF2CF2CF3 .......................................... CF3CF2OCH2CHF2 ....................................... CH3OCF(CF3)2 .............................................. (CF3)2CHOCH2F ........................................... CHF2CF2OCH2CF3 ....................................... CH3OCF2CHFCF3 ......................................... CF3CH2OCH2CF3 .......................................... (CF3)2CHOCH3 .............................................. CH3OCF2CF2CHF2 ....................................... CHF2CH2OCF2CHF2 ..................................... CHF2OCH2CF2CHF2 ..................................... CF3CF2OCH2CH3 .......................................... CF3CF2CH2OCH3 .......................................... CH3CH2OCF2CHF2 ....................................... C4F9OCH3 ..................................................... (CF3)2CFCF2OCH3 ........................................ C4F9OC2H5 .................................................... (CF3)2CFCF2OC2H5 ...................................... (CF3)2CFCFOC2H5CF2CF2CF3 ..................... n-C3F7CFOC2H5CF(CF3)2 ............................. CH3OCF2CF2OCH3 ....................................... CH3O(CF2CF2O)2CH3 ................................... CH3O(CF2CF2O)3CH3 ................................... CH3OCHF2 .................................................... CH3OCF2CHFCl ............................................ CF3CF2CF2OCH2CH3 ................................... C12H5F19O2 ................................................... 380–34–7 460–22–0 60598–17–6 CF3CHFCF2OCH2CH3 .................................. CH3OCH2F .................................................... CHF2CF2CH2OCH3 ....................................... 37031–31–5 461–63–2 462–51–1 CH2FOCF2CF2H ............................................ CH2FOCHF2 .................................................. CH2FOCH2F .................................................. d 523 d 654 d 828 d 812 d 301 d1 b 29 d 530 d 854 d 363 c 216 d 889 d 387 b 17 d 14 d 413 d 719 d 446 b 58 d 0.99 d 627 d 421 ........................ d 57 ........................ e 405 e 13 b 222 b 236 b 221 b 144 b 122 b 61 b 56 b 23 b 13 b d 0.49 b 871 b 617 b 130 Saturated Chlorofluorocarbons (CFCs) E–R316c ................................................................................ Z–R316c ................................................................................ 3832–15–3 3934–26–7 trans-cyc (-CClFCF2CF2CClF-) ..................... cis-cyc (-CClFCF2CF2CClF-) ......................... e 4,230 e 5,660 lotter on DSK11XQN23PROD with RULES2 Fluorinated Formates Trifluoromethyl formate .......................................................... Perfluoroethyl formate ........................................................... 1,2,2,2-Tetrafluoroethyl formate ............................................ Perfluorobutyl formate ........................................................... Perfluoropropyl formate ......................................................... 1,1,1,3,3,3-Hexafluoropropan-2-yl formate ............................ 2,2,2-Trifluoroethyl formate ................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00096 85358–65–2 313064–40–3 481631–19–0 197218–56–7 271257–42–2 856766–70–6 32042–38–9 Fmt 4701 Sfmt 4700 HCOOCF3 ...................................................... HCOOCF2CF3 ............................................... HCOOCHFCF3 .............................................. HCOOCF2CF2CF2CF3 .................................. HCOOCF2CF2CF3 ......................................... HCOOCH(CF3)2 ............................................ HCOOCH2CF3 ............................................... E:\FR\FM\25APR2.SGM 25APR2 b 588 b 580 b 470 b 392 b 376 b 333 b 33 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31897 TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS, 100-YEAR TIME HORIZON—Continued Name CAS No. 3,3,3-Trifluoropropyl formate ................................................. 1344118–09–7 Chemical formula HCOOCH2CH2CF3 ........................................ Global warming potential (100 yr.) b 17 Fluorinated Acetates Methyl 2,2,2-trifluoroacetate .................................................. 1,1-Difluoroethyl 2,2,2-trifluoroacetate .................................. Difluoromethyl 2,2,2-trifluoroacetate ...................................... 2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate ............................... Methyl 2,2-difluoroacetate ..................................................... Perfluoroethyl acetate ............................................................ Trifluoromethyl acetate .......................................................... Perfluoropropyl acetate ......................................................... Perfluorobutyl acetate ............................................................ Ethyl 2,2,2-trifluoroacetate ..................................................... 431–47–0 1344118–13–3 2024–86–4 407–38–5 433–53–4 343269–97–6 74123–20–9 1344118–10–0 209597–28–4 383–63–1 CF3COOCH3 ................................................. CF3COOCF2CH3 ........................................... CF3COOCHF2 ............................................... CF3COOCH2CF3 ........................................... HCF2COOCH3 ............................................... CH3COOCF2CF3 ........................................... CH3COOCF3 ................................................. CH3COOCF2CF2CF3 ..................................... CH3COOCF2CF2CF2CF3 .............................. CF3COOCH2CH3 ........................................... b 52 b 31 b 27 b7 b3 bd2 bd2 bd2 bd2 bd1 Carbonofluoridates Methyl carbonofluoridate ....................................................... 1,1-Difluoroethyl carbonofluoridate ........................................ 1538–06–3 1344118–11–1 FCOOCH3 ...................................................... FCOOCF2CH3 ............................................... b 95 b 27 Fluorinated Alcohols Other Than Fluorotelomer Alcohols Bis(trifluoromethyl)-methanol ................................................. 2,2,3,3,4,4,5,5-Octafluorocyclopentanol ................................ 2,2,3,3,3-Pentafluoropropanol ............................................... 2,2,3,3,4,4,4-Heptafluorobutan-1-ol ....................................... 2,2,2-Trifluoroethanol ............................................................. 2,2,3,4,4,4-Hexafluoro-1-butanol ........................................... 2,2,3,3-Tetrafluoro-1-propanol ............................................... 2,2-Difluoroethanol ................................................................ 2-Fluoroethanol ...................................................................... 4,4,4-Trifluorobutan-1-ol ........................................................ 920–66–1 16621–87–7 422–05–9 375–01–9 75–89–8 382–31–0 76–37–9 359–13–7 371–62–0 461–18–7 (CF3)2CHOH .................................................. cyc (-(CF2)4CH(OH)-) .................................... CF3CF2CH2OH .............................................. C3F7CH2OH .................................................. CF3CH2OH .................................................... CF3CHFCF2CH2OH ...................................... CHF2CF2CH2OH ........................................... CHF2CH2OH ................................................. CH2FCH2OH .................................................. CF3(CH2)2CH2OH ......................................... d 182 d 13 d 19 b d 34 b 20 b 17 b 13 b3 b 1.1 b 0.05 Non-Cyclic, Unsaturated Perfluorocarbons (PFCs) PFC–1114; TFE ..................................................................... PFC–1216; Dyneon HFP ....................................................... Perfluorobut-2-ene ................................................................. Perfluorobut-1-ene ................................................................. Perfluorobuta-1,3-diene ......................................................... 116–14–3 116–15–4 360–89–4 357–26–6 685–63–2 CF2 = CF2; C2F4 ........................................... C3F6; CF3CF = CF2 ....................................... CF3CF = CFCF3 ............................................ CF3CF2CF = CF2 .......................................... CF2 = CFCF = CF2 ....................................... b 0.004 b 0.05 b 1.82 b 0.10 b 0.003 lotter on DSK11XQN23PROD with RULES2 Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs) HFC–1132a; VF2 ................................................................... HFC–1141; VF ....................................................................... (E)-HFC–1225ye .................................................................... (Z)-HFC–1225ye .................................................................... Solstice 1233zd(E) ................................................................ HCFO–1233zd(Z) .................................................................. HFC–1234yf; HFO–1234yf .................................................... HFC–1234ze(E) ..................................................................... HFC–1234ze(Z) ..................................................................... HFC–1243zf; TFP .................................................................. (Z)-HFC–1336 ........................................................................ HFO–1336mzz(E) .................................................................. HFC–1345zfc ......................................................................... HFO–1123 ............................................................................. HFO–1438ezy(E) ................................................................... HFO–1447fz .......................................................................... Capstone 42–U ...................................................................... Capstone 62–U ...................................................................... Capstone 82–U ...................................................................... (e)-1-chloro-2-fluoroethene .................................................... 3,3,3-trifluoro-2-(trifluoromethyl)prop-1-ene ........................... 75–38–7 75–02–5 5595–10–8 5528–43–8 102687–65–0 99728–16–2 754–12–1 1645–83–6 29118–25–0 677–21–4 692–49–9 66711–86–2 374–27–6 359–11–5 14149–41–8 355–08–8 19430–93–4 25291–17–2 21652–58–4 460–16–2 382–10–5 C2H2F2, CF2 = CH2 ....................................... C2H3F, CH2 = CHF ....................................... CF3CF = CHF(E) ........................................... CF3CF = CHF(Z) ........................................... C3H2ClF3; CHCl = CHCF3 ............................ (Z)-CF3CH = CHCl ........................................ C3H2F4; CF3CF = CH2 .................................. C3H2F4; trans-CF3CH = CHF ........................ C3H2F4; cis-CF3CH = CHF; CF3CH = CHF .. C3H3F3, CF3CH = CH2 .................................. CF3CH = CHCF3(Z) ...................................... (E)-CF3CH = CHCF3 ..................................... C2F5CH = CH2 .............................................. CHF=CF2 ....................................................... (E)-(CF3)2CFCH = CHF ................................. CF3(CF2)2CH = CH2 ...................................... C6H3F9, CF3(CF2)3CH = CH2 ....................... C8H3F13, CF3(CF2)5CH = CH2 ...................... C10H3F17, CF3(CF2)7CH = CH2 .................... (E)-CHCl = CHF ............................................ (CF3)2C = CH2 ............................................... b 0.04 b 0.02 b 0.06 b 0.22 b 1.34 e 0.45 b 0.31 b 0.97 b 0.29 b 0.12 b 1.58 e 18 b 0.09 e 0.005 e 8.2 e 0.24 b 0.16 b 0.11 b 0.09 e 0.004 e 0.38 Non-Cyclic, Unsaturated CFCs CFC–1112 ............................................................................. CFC–1112a ........................................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00097 598–88–9 79–35–6 Fmt 4701 Sfmt 4700 CClF=CClF .................................................... CCl2=CF2 ....................................................... E:\FR\FM\25APR2.SGM 25APR2 e 0.13 e 0.021 31898 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS, 100-YEAR TIME HORIZON—Continued Name CAS No. Chemical formula Global warming potential (100 yr.) Non-Cyclic, Unsaturated Halogenated Ethers PMVE; HFE–216 ................................................................... Fluoroxene ............................................................................. Methyl-perfluoroheptene-ethers ............................................. 1187–93–5 406–90–6 N/A CF3OCF = CF2 .............................................. CF3CH2OCH = CH2 ...................................... CH3OC7F13 .................................................... b 0.17 b 0.05 e 15 Non-Cyclic, Unsaturated Halogenated Esters Ethenyl 2,2,2-trifluoroacetate ................................................. Prop-2-enyl 2,2,2-trifluoroacetate .......................................... 433–28–3 383–67–5 CF3COOCH=CH2 .......................................... CF3COOCH2CH=CH2 ................................... e 0.008 e 0.007 Cyclic, Unsaturated HFCs and PFCs PFC C–1418 .......................................................................... Hexafluorocyclobutene .......................................................... 1,3,3,4,4,5,5-heptafluorocyclopentene .................................. 1,3,3,4,4-pentafluorocyclobutene .......................................... 3,3,4,4-tetrafluorocyclobutene ............................................... 559–40–0 697–11–0 1892–03–1 374–31–2 2714–38–7 c-C5F8 ............................................................ cyc (-CF=CFCF2CF2-) ................................... cyc (-CF2CF2CF2CF=CH-) ............................ cyc (-CH=CFCF2CF2-) ................................... cyc (-CH=CHCF2CF2-) .................................. d2 e 126 e 45 e 92 e 26 Fluorinated Aldehydes 3,3,3-Trifluoro-propanal ......................................................... 460–40–2 CF3CH2CHO .................................................. b 0.01 Fluorinated Ketones Novec 1230 (perfluoro (2-methyl-3-pentanone)) ................... 1,1,1-trifluoropropan-2-one .................................................... 1,1,1-trifluorobutan-2-one ...................................................... 756–13–8 421–50–1 381–88–4 CF3CF2C(O)CF (CF3)2 ................................. CF3COCH3 .................................................... CF3COCH2CH3 ............................................. b 0.1 e 0.09 e 0.095 Fluorotelomer Alcohols 3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol ...................... 3,3,3-Trifluoropropan-1-ol ...................................................... 3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol ...... 3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11Nonadecafluoroundecan-1-ol. 185689–57–0 2240–88–2 755–02–2 87017–97–8 CF3(CF2)4CH2CH2OH ................................... CF3CH2CH2OH ............................................. CF3(CF2)6CH2CH2OH ................................... CF3(CF2)8CH2CH2OH ................................... b 0.43 b 0.35 b 0.33 b 0.19 Fluorinated GHGs With Carbon-Iodine Bond(s) Trifluoroiodomethane ............................................................. 2314–97–8 CF3I ............................................................... b 0.4 Remaining Fluorinated GHGs with Chemical-Specific GWPs Dibromodifluoromethane (Halon 1202) ................................. 2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-2311/ Halothane). Heptafluoroisobutyronitrile ..................................................... Carbonyl fluoride ................................................................... 75–61–6 151–67–7 CBr2F2 ........................................................... CHBrClCF3 .................................................... b 231 42532–60–5 353–50–4 (CF3)2CFCN .................................................. COF2 .............................................................. e 2,750 b 41 e 0.14 Global warming potential (100 yr.) Fluorinated GHG group f lotter on DSK11XQN23PROD with RULES2 Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not Listed Above Fully fluorinated GHGs g .................................................................................................................................................................... Saturated hydrofluorocarbons (HFCs) with 2 or fewer carbon-hydrogen bonds g ............................................................................ Saturated HFCs with 3 or more carbon-hydrogen bonds g ............................................................................................................... Saturated hydrofluoroethers (HFEs) and hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen bond g .................................. Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds g ......................................................................................................... Saturated HFEs and HCFEs with 3 or more carbon-hydrogen bonds g ........................................................................................... Saturated chlorofluorocarbons (CFCs) g ............................................................................................................................................ Fluorinated formates .......................................................................................................................................................................... Cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons (BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated hydrobromofluorocarbons (HBFCs), unsaturated hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, and unsaturated halogenated esters g ................................................................................................ Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols g ......................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00098 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 9,200 3,000 840 6,600 2,900 320 4,900 350 58 25 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31899 Global warming potential (100 yr.) Fluorinated GHG group f Fluorinated aldehydes, fluorinated ketones, and non-cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers and unsaturated halogenated esters g ...................................................... Fluorotelomer alcohols g .................................................................................................................................................................... Fluorinated GHGs with carbon-iodine bond(s) g ................................................................................................................................ Other fluorinated GHGs g ................................................................................................................................................................... 1 1 1 1,800 a The GWP for this compound was updated in the final rule published on November 29, 2013 [78 FR 71904] and effective on January 1, 2014. compound was added to table A–1 in the final rule published on December 11, 2014, and effective on January 1, 2015. c The GWP for this compound was updated in the final rule published on December 11, 2014, and effective on January 1, 2015. d The GWP for this compound was updated in the final rule published on April 25, 2024 and effective on January 1, 2025. e The GWP for this compound was added to table A–1 in the final rule published on April 25, 2024 and effective on January 1, 2025. f For electronics manufacturing (as defined in § 98.90), the term ‘‘fluorinated GHGs’’ in the definition of each fluorinated GHG group in § 98.6 shall include fluorinated heat transfer fluids (as defined in § 98.6), whether or not they are also fluorinated GHGs. g The GWP for this fluorinated GHG group was updated in the final rule published on April 25, 2024 and effective on January 1, 2025. b This 10. Revise and republish table A–3 to subpart A to read as follows: ■ TABLE A–3 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(1) Source Categories a Applicable in Reporting Year 2010 and Future Years: Electricity generation units that report CO2 mass emissions year round through 40 CFR part 75 (subpart D). Adipic acid production (subpart E of this part). Aluminum production (subpart F of this part). Ammonia manufacturing (subpart G of this part). Cement production (subpart H of this part). HCFC–22 production (subpart O of this part). HFC–23 destruction processes that are not collocated with a HCFC–22 production facility and that destroy more than 2.14 metric tons of HFC–23 per year (subpart O of this part). Lime manufacturing (subpart S of this part). Nitric acid production (subpart V of this part). Petrochemical production (subpart X of this part). Petroleum refineries (subpart Y of this part). Phosphoric acid production (subpart Z of this part). Silicon carbide production (subpart BB of this part). Soda ash production (subpart CC of this part). Titanium dioxide production (subpart EE of this part). Municipal solid waste landfills that generate CH4 in amounts equivalent to 25,000 metric tons CO2e or more per year, as determined according to subpart HH of this part. Manure management systems with combined CH4 and N2O emissions in amounts equivalent to 25,000 metric tons CO2e or more per year, as determined according to subpart JJ of this part. Additional Source Categories a Applicable in Reporting Year 2011 and Future Years: Electrical transmission and distribution equipment use at facilities where the total estimated emissions from fluorinated GHGs, as determined under § 98.301 (subpart DD of this part), are equivalent to 25,000 metric tons CO2e or more per year. Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or more per year (subpart FF of this part). Geologic sequestration of carbon dioxide (subpart RR of this part). Injection of carbon dioxide (subpart UU of this part). Additional Source Categories a Applicable in Reporting Year 2025 and Future Years: Geologic sequestration of carbon dioxide with enhanced oil recovery using ISO 27916 (subpart VV of this part). Coke calciners (subpart WW of this part). Calcium carbide production (subpart XX of this part). Caprolactam, glyoxal, and glyoxylic acid production (subpart YY of this part). a Source categories are defined in each applicable subpart of this part. 11. Revise and republish table A–4 to subpart A to read as follows: ■ lotter on DSK11XQN23PROD with RULES2 TABLE A–4 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(2) Source Categories a Applicable in Reporting Year 2010 and Future Years: Ferroalloy production (subpart K of this part). Glass production (subpart N of this part). Hydrogen production (subpart P of this part). Iron and steel production (subpart Q of this part). Lead production (subpart R of this part). Pulp and paper manufacturing (subpart AA of this part). Zinc production (subpart GG of this part). Additional Source Categories a Applicable in Reporting Year 2011 and Future Years: VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00099 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31900 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE A–4 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(2)—Continued Electronics manufacturing (subpart I of this part). Fluorinated gas production (subpart L of this part). Magnesium production (subpart T of this part). Petroleum and Natural Gas Systems (subpart W of this part). Industrial wastewater treatment (subpart II of this part). Electrical transmission and distribution equipment manufacture or refurbishment, as determined under § 98.451 (subpart SS of this part). Industrial waste landfills (subpart TT of this part). Additional Source Categories a Applicable in Reporting Year 2025 and Future Years: Ceramics manufacturing facilities, as determined under § 98.520 (subpart ZZ of this part). a Source categories are defined in each applicable subpart. d. Revising and republishing paragraph (c)(6); ■ e. Revising parameter ‘‘R’’ of equation C–11 in paragraph (d)(1); and ■ f. Revising the introductory text of paragraphs (e), (e)(1) and (3), and paragraph (e)(3)(iv). The revisions read as follows: ■ Subpart C—General Stationary Fuel Combustion Sources 12. Amend § 98.33 by: a. Revising and republishing paragraph (a)(3)(iii); ■ b. Revising paragraph (b)(1)(vii); ■ c. Revising parameter ‘‘EF’’ of equation C–10 in paragraph (c)(4) introductory text; ■ ■ § 98.33 Calculating GHG emissions. * * * * * (a) * * * (3) * * * (iii) For a gaseous fuel, use equation C–5 to this section. 44 MW CO 2 = -12 * Fuel * CC * - * 0 001 MVC • (Eq. C-5) Where: CO2 = Annual CO2 mass emissions from combustion of the specific gaseous fuel (metric tons). Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to § 98.3(i). Fuel billing meters may be used for this purpose. CC = Annual average carbon content of the gaseous fuel (kg C per kg of fuel). The annual average carbon content shall be determined using the procedures specified in paragraphs (a)(3)(iii)(A)(1) and (2) of this section. MW = Annual average molecular weight of the gaseous fuel (kg per kg-mole). The annual average molecular weight shall be determined using the procedures ( specified in paragraphs (a)(3)(iii)(B)(1) and (2) of this section. MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg mole if you select 68 °F as standard temperature and 836.6 scf per kg mole if you select 60 °F as standard temperature. 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons. (A) The minimum required sampling frequency for determining the annual average carbon content (e.g., monthly, quarterly, semi-annually, or by lot) is specified in § 98.34. The method for computing the annual average carbon content for equation C–5 to this section is a function of unit size and how frequently you perform or receive from the fuel supplier the results of fuel sampling for carbon content. The methods are specified in paragraphs (a)(3)(iii)(A)(1) and (2) of this section, as applicable. (1) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of units that includes at least one unit of that size), the annual average carbon content for equation C–5 shall be calculated using equation C–5A to this section. If multiple carbon content determinations are made in any month, average the values for the month arithmetically. _ Ir=i (CC)i * (Fuel)i * (MW)JMWC CC annual Ir=1 (Fuel)i * (MW)JMVC ) VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 appropriate substitute data value (kg C per kg of fuel). (Fuel)i = Volume of the fuel (scf) combusted during the sample period ‘‘i’’ (e.g., monthly, quarterly, semi-annually, or by lot) from company records. (MW)i = Measured molecular weight of the fuel, for sample period ‘‘i’’ (which may PO 00000 Frm 00100 Fmt 4701 Sfmt 4700 be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg per kg-mole). MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg-mole if you select 68 °F as standard temperature and 836.6 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.001</GPH> Where: (CC)annual = Weighted annual average carbon content of the fuel (kg C per kg of fuel). (CC)i = Measured carbon content of the fuel, for sample period ‘‘i’’ (which may be the arithmetic average of multiple determinations), or, if applicable, an ER25AP24.000</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. C-5A) Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations scf per kg-mole if you select 60 °F as standard temperature. n = Number of sample periods in the year. (2) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the carbon content sampling frequency, the annual average carbon content for equation C–5 shall either be computed according to paragraph (a)(3)(iii)(A)(1) of this section or as the arithmetic average carbon content for all values for (MW)annual = the year (including valid samples and substitute data values under § 98.35). (B) The minimum required sampling frequency for determining the annual average molecular weight (e.g., monthly, quarterly, semi-annually, or by lot) is specified in § 98.34. The method for computing the annual average molecular weight for equation C–5 is a function of unit size and how frequently you perform or receive from the fuel supplier the results of fuel sampling for molecular weight. The methods are specified in paragraphs (a)(3)(iii)(B)(1) and (2) of this section, as applicable. 31901 (1) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of units that includes at least one unit of that size), the annual average molecular weight for equation C–5 shall be calculated using equation C–5B to this section. If multiple molecular weight determinations are made in any month, average the values for the month arithmetically. Lr i (MW)i * (Fuel)JMVC Ir=i (Fuel)JMVC (Eq. C-5B) (2) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the molecular weight sampling frequency, the annual average molecular weight for equation C–5 shall either be computed according to paragraph (a)(3)(iii)(B)(1) of this section or as the arithmetic average molecular weight for all values for the year (including valid samples and substitute data values under § 98.35). * * * * * (b) * * * (1) * * * (vii) May be used for the combustion of MSW and/or tires in a unit, provided that no more than 10 percent of the unit’s annual heat input is derived from those fuels, combined. * * * * * (c) * * * (4) * * * VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 EF = Fuel-specific emission factor for CH4 or N2O, from table C–2 to this subpart (kg CH4 or N2O per mmBtu). * * * * * (6) Calculate the annual CH4 and N2O mass emissions from the combustion of blended fuels as follows: (i) If the mass, volume, or heat input of each component fuel in the blend is determined before the fuels are mixed and combusted, calculate and report CH4 and N2O emissions separately for each component fuel, using the applicable procedures in this paragraph (c). (ii) If the mass, volume, or heat input of each component fuel in the blend is not determined before the fuels are mixed and combusted, a reasonable estimate of the percentage composition of the blend, based on best available information, is required. Perform the following calculations for each component fuel ‘‘i’’ that is listed in table C–2 to this subpart: (A) Multiply (% Fuel)i, the estimated mass, volume, or heat input percentage of component fuel ‘‘i’’ (expressed as a decimal fraction), by the total annual mass, volume, or heat input of the blended fuel combusted during the reporting year, to obtain an estimate of the annual value for component ‘‘i’’; (B) [Reserved] (C) Calculate the annual CH4 and N2O emissions from component ‘‘i’’, using equation C–8 (fuel mass or volume) to this section, C–8a (fuel heat input) to this section, C–8b (fuel heat input) to this section, C–9a (fuel mass or volume) to this section, or C–10 (fuel heat input) to this section, as applicable; (D) Sum the annual CH4 emissions across all component fuels to obtain the annual CH4 emissions for the blend. PO 00000 Frm 00101 Fmt 4701 Sfmt 4700 Similarly sum the annual N2O emissions across all component fuels to obtain the annual N2O emissions for the blend. Report these annual emissions totals. (d) * * * (1) * * * R = The number of moles of CO2 released per mole of sorbent used (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas species is SO2). * * * * * (e) Biogenic CO2 emissions from combustion of biomass with other fuels. Use the applicable procedures of this paragraph (e) to estimate biogenic CO2 emissions from units that combust a combination of biomass and fossil fuels (i.e., either co-fired or blended fuels). Separate reporting of biogenic CO2 emissions from the combined combustion of biomass and fossil fuels is required for those biomass fuels listed in table C–1 to this subpart, MSW, and tires. In addition, when a biomass fuel that is not listed in table C–1 to this subpart is combusted in a unit that has a maximum rated heat input greater than 250 mmBtu/hr, if the biomass fuel accounts for 10% or more of the annual heat input to the unit, and if the unit does not use CEMS to quantify its annual CO2 mass emissions, then, pursuant to paragraph (b)(3)(iii) of this section, Tier 3 must be used to determine the carbon content of the biomass fuel and to calculate the biogenic CO2 emissions from combustion of the fuel. Notwithstanding these requirements, in accordance with § 98.3(c)(12), separate reporting of biogenic CO2 emissions is optional for the 2010 reporting year for units subject to subpart D of this part and for units E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.002</GPH> lotter on DSK11XQN23PROD with RULES2 Where: (MW)annual = Weighted annual average molecular weight of the fuel (kg per kgmole). (MW)i = Measured molecular weight of the fuel, for sample period ‘‘i’’ (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg per kg-mole). (Fuel)i = Volume of the fuel (scf) combusted during the sample period ‘‘i’’ (e.g., monthly, quarterly, semi-annually, or by lot) from company records. MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg-mole if you select 68 °F as standard temperature and 836.6 scf per kg-mole if you select 60 °F as standard temperature. n = Number of sample periods in the year. lotter on DSK11XQN23PROD with RULES2 31902 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations that use the CO2 mass emissions calculation methodologies in part 75 of this chapter, pursuant to paragraph (a)(5) of this section. However, if the owner or operator opts to report biogenic CO2 emissions separately for these units, the appropriate method(s) in this paragraph (e) shall be used. (1) You may use equation C–1 to this section to calculate the annual CO2 mass emissions from the combustion of the biomass fuels listed in table C–1 to this subpart, in a unit of any size, including units equipped with a CO2 CEMS, except when the use of Tier 2 is required as specified in paragraph (b)(1)(iv) of this section. Determine the quantity of biomass combusted using one of the following procedures in this paragraph (e)(1), as appropriate, and document the selected procedures in the Monitoring Plan under § 98.3(g): * * * * * (3) You must use the procedures in paragraphs (e)(3)(i) through (iii) of this section to determine the annual biogenic CO2 emissions from the combustion of MSW, except as otherwise provided in paragraph (e)(3)(iv) of this section. These procedures also may be used for any unit that co-fires biomass and fossil fuels, including units equipped with a CO2 CEMS. * * * * * (iv) In lieu of following the procedures in paragraphs (e)(3)(i) through (iii) of this section, the procedures of this paragraph (e)(3)(iv) may be used for the combustion of tires regardless of the percent of the annual heat input provided by tires. The calculation procedure in this paragraph (e)(3)(iv) may be used for the combustion of MSW if the combustion of MSW provides no more than 10 percent of the annual heat input to the unit or if a small, batch incinerator combusts no more than 1,000 tons per year of MSW. (A) Calculate the total annual CO2 emissions from combustion of MSW and/or tires in the unit, using the applicable methodology in paragraphs (a)(1) through (3) of this section for units using Tier 1, Tier 2, or Tier 3; otherwise use the Tier 1 calculation methodology in paragraph (a)(1) of this section for units using either the Tier 4 or Alternative Part 75 calculation methodologies to calculate total CO2 emissions. (B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO2 emissions, in metric tons. For MSW, use a default VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 factor of 0.60 and for tires, use a default factor of 0.24. * * * * * ■ 13. Amend § 98.34 by revising paragraphs (c)(6), (d) and (e) to read as follows: § 98.34 Monitoring and QA/QC requirements. * * * * * (c) * * * (6) For applications where CO2 concentrations in process and/or combustion flue gasses are lower or higher than the typical CO2 span value for coal-based fuels (e.g., 20 percent CO2 for a coal fired boiler), cylinder gas audits of the CO2 monitor under appendix F to part 60 of this chapter may be performed at 40–60 percent and 80–100 percent of CO2 span, in lieu of the prescribed calibration levels of 5–8 percent and 10–14 percent CO2 by volume. * * * * * (d) Except as otherwise provided in § 98.33(e)(3)(iv), when municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit, determine the biogenic portion of the CO2 emissions using ASTM D6866–16 and ASTM D7459–08 (both incorporated by reference, see § 98.7). Perform the ASTM D7459–08 sampling and the ASTM D6866–16 analysis at least once in every calendar quarter in which MSW is combusted in the unit. Collect each gas sample during normal unit operating conditions for at least 24 total (not necessarily consecutive) hours, or longer if the facility deems it necessary to obtain a representative sample. Notwithstanding this requirement, if the types of fuels combusted and their relative proportions are consistent throughout the year, the minimum required sampling time may be reduced to 8 hours if at least two 8-hour samples and one 24-hour sample are collected under normal operating conditions, and arithmetic average of the biogenic fraction of the flue gas from the 8-hour samples (expressed as a decimal) is within ±5 percent of the biogenic fraction from the 24-hour test. There must be no overlapping of the 8-hour and 24-hour test periods. Document the results of the demonstration in the unit’s monitoring plan. If the types of fuels and their relative proportions are not consistent throughout the year, an optional sampling approach that facilities may wish to consider to obtain a more representative sample is to collect an integrated sample by extracting a small amount of flue gas PO 00000 Frm 00102 Fmt 4701 Sfmt 4700 (e.g., 1 to 5 cc) in each unit operating hour during the quarter. Separate the total annual CO2 emissions into the biogenic and non-biogenic fractions using the average proportion of biogenic emissions of all samples analyzed during the reporting year. Express the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO2 is biogenic). When MSW is the primary fuel for multiple units at the facility, and the units are fed from a common fuel source, testing at only one of the units is sufficient. (e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels that have a biomass component, e.g., tires) and fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866–16 and ASTM D7459–08 (both incorporated by reference, see § 98.7) may be used to determine the biogenic portion of the CO2 emissions in every calendar quarter in which biomass and non-biogenic fuels are co-fired in the unit. Follow the procedures in paragraph (d) of this section. If multiple units at the facility are fed from a common fuel source, testing at only one of the units is sufficient. * * * * * ■ 14. Amend § 98.36 by revising paragraphs (c)(1)(vi), (c)(3)(vi), (e)(2)(ii)(C) and (e)(2)(xi) to read as follows: § 98.36 Data reporting requirements. * * * * * (c) * * * (1) * * * (vi) Annual CO2 mass emissions and annual CH4, and N2O mass emissions, aggregated for each type of fuel combusted in the group of units during the report year, expressed in metric tons of each gas and in metric tons of CO2e. If any of the units burn biomass, report also the annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons. * * * * * (3) * * * (vi) If any of the units burns biomass, the annual CO2 emissions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons. * * * * * (e) * * * (2) * * * (ii) * * * (C) The annual average, and, where applicable, monthly high heat values used in the CO2 emissions calculations for each type of fuel combusted during the reporting year, in mmBtu per short ton for solid fuels, mmBtu per gallon for E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations liquid fuels, and mmBtu per scf for gaseous fuels. Report an HHV value for each calendar month in which HHV determination is required. If multiple values are obtained in a given month, report the arithmetic average value for the month. * * * * * (xi) When ASTM methods D7459–08 and D6866–16 (both incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine the biogenic portion of the annual CO2 emissions from a unit that co-fires biogenic fuels (or partly-biogenic fuels, including tires) and non-biogenic fuels, you shall report the results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions is 30 percent, report 0.30). * * * * * ■ 15. Amend § 98.37 by revising and republishing paragraph (b) to read as follows: § 98.37 Records that must be retained. lotter on DSK11XQN23PROD with RULES2 * * * * * (b) The applicable verification software records as identified in this paragraph (b). For each stationary fuel combustion source that elects to use the verification software specified in § 98.5(b) rather than report data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (C), and (D), (e)(2)(iv)(A), (C), and (F), and (e)(2)(ix)(D) through (F) of this section, you must keep a record of the file generated by the verification software for the applicable data specified in paragraphs (b)(1) through (37) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (37) of this section. (1) Mass of each solid fuel combusted (tons/year) (equation C–1 to § 98.33). (2) Volume of each liquid fuel combusted (gallons/year) (equation C–1 to § 98.33). (3) Volume of each gaseous fuel combusted (scf/year) (equation C–1 to § 98.33). (4) Annual natural gas usage (therms/ year) (equation C–1a to § 98.33). (5) Annual natural gas usage (mmBtu/ year) (equation C–1b to § 98.33). (6) Mass of each solid fuel combusted (tons/year) (equation C–2a to § 98.33). (7) Volume of each liquid fuel combusted (gallons/year) (equation C– 2a to § 98.33). (8) Volume of each gaseous fuel combusted (scf/year) (equation C–2a to § 98.33). (9) Measured high heat value of each solid fuel, for month (which may be the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per ton) (equation C–2b to § 98.33). Annual average HHV of each solid fuel (mmBtu per ton) (equation C– 2a to § 98.33). (10) Measured high heat value of each liquid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per gallons) (equation C–2b to § 98.33). Annual average HHV of each liquid fuel (mmBtu per gallons) (equation C–2a to § 98.33). (11) Measured high heat value of each gaseous fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per scf) (equation C–2b to § 98.33). Annual average HHV of each gaseous fuel (mmBtu per scf) (equation C–2a to § 98.33). (12) Mass of each solid fuel combusted during month (tons) (equation C–2b to § 98.33). (13) Volume of each liquid fuel combusted during month (gallons) (equation C–2b to § 98.33). (14) Volume of each gaseous fuel combusted during month (scf) (equation C–2b, equation C–5A, equation C–5B to § 98.33). (15) Total mass of steam generated by municipal solid waste or each solid fuel combustion during the reporting year (pounds steam) (equation C–2c to § 98.33). (16) Ratio of the boiler’s maximum rated heat input capacity to its design rated steam output capacity (MMBtu/ pounds steam) (equation C–2c to § 98.33). (17) Annual mass of each solid fuel combusted (short tons/year) (equation C–3 to § 98.33). (18) Annual average carbon content of each solid fuel (percent by weight, expressed as a decimal fraction) (equation C–3 to § 98.33). Where applicable, monthly carbon content of each solid fuel (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (percent by weight, expressed as a decimal fraction) (equation C–2b to § 98.33—see the definition of ‘‘CC’’ in equation C–3 to § 98.33). (19) Annual volume of each liquid fuel combusted (gallons/year) (equation C–4 to § 98.33). (20) Annual average carbon content of each liquid fuel (kg C per gallon of fuel) (equation C–4 to § 98.33). Where applicable, monthly carbon content of each liquid fuel (which may be the PO 00000 Frm 00103 Fmt 4701 Sfmt 4700 31903 arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg C per gallon of fuel) (equation C–2b to § 98.33—see the definition of ‘‘CC’’ in equation C–3 to § 98.33). (21) Annual volume of each gaseous fuel combusted (scf/year) (equation C–5 to § 98.33). (22) Annual average carbon content of each gaseous fuel (kg C per kg of fuel) (equation C–5 to § 98.33). Where applicable, monthly carbon content of each gaseous (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg C per kg of fuel) (equation C–5A to § 98.33). (23) Annual average molecular weight of each gaseous fuel (kg/kg-mole) (equation C–5 to § 98.33). Where applicable, monthly molecular weight of each gaseous (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg/kgmole) (equation C–5B to § 98.33). (24) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (equation C–5 to § 98.33). (25) Identify for each fuel if you will use the default high heat value from table C–1 to this subpart, or actual high heat value data (equation C–8 to § 98.33). (26) High heat value of each solid fuel (mmBtu/tons) (equation C–8 to § 98.33). (27) High heat value of each liquid fuel (mmBtu/gallon) (equation C–8 to § 98.33). (28) High heat value of each gaseous fuel (mmBtu/scf) (equation C–8 to § 98.33). (29) Cumulative annual heat input from combustion of each fuel (mmBtu) (equation C–10 to § 98.33). (30) Total quantity of each solid fossil fuel combusted in the reporting year, as defined in § 98.6 (pounds) (equation C– 13 to § 98.33). (31) Total quantity of each liquid fossil fuel combusted in the reporting year, as defined in § 98.6 (gallons) (equation C–13 to § 98.33). (32) Total quantity of each gaseous fossil fuel combusted in the reporting year, as defined in § 98.6 (scf) (equation C–13 to § 98.33). (33) High heat value of the each solid fossil fuel (Btu/lb) (equation C–13 to § 98.33). (34) High heat value of the each liquid fossil fuel (Btu/gallons) (equation C–13 to § 98.33). (35) High heat value of the each gaseous fossil fuel (Btu/scf) (equation C– 13 to § 98.33). E:\FR\FM\25APR2.SGM 25APR2 31904 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (a) CO2 process emissions from steam reforming of a hydrocarbon or the gasification of solid and liquid raw material, reported for each ammonia manufacturing unit following the requirements of this subpart. * * * * * ■ 17. Amend § 98.73 by revising the introductory text and paragraph (b) to read as follows: * * § 98.73 GHGs to report. * * * CO2 G = ' Calculating GHG emissions. You must calculate and report the annual CO2 process emissions from each (L n=i -12 * Fdstkn * CCn * iZ 44 MW) MVC MW = Molecular weight of the gaseous feedstock (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons. n = Number of month. Where: CO2,G = Annual CO2 emissions arising from gaseous feedstock consumption (metric tons). Fdstkn = Volume of the gaseous feedstock used in month n (scf of feedstock). CCn = Carbon content of the gaseous feedstock, for month n (kg C per kg of feedstock), determined according to § 98.74(c). CO2,L = (L 12n=112- * Fdstkn * CCn 44 Where: CO2,L = Annual CO2 emissions arising from liquid feedstock consumption (metric tons). Fdstkn = Volume of the liquid feedstock used in month n (gallons of feedstock). CCn = Carbon content of the liquid feedstock, for month n (kg C per gallon of CO 2,s = 44 ) (2) Liquid feedstock. You must calculate, from each ammonia manufacturing unit, the CO2 process emissions from liquid feedstock according to equation G–2 to this section: (Eq. G-2) * 0.001 feedstock) determined according to § 98.74(c). 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons. n = Number of month. 12 (L n=112 - * Fdstkn * CCn Where: CO2,S = Annual CO2 emissions arising from solid feedstock consumption (metric tons). Fdstkn = Mass of the solid feedstock used in month n (kg of feedstock). ) (Eq. G-1) * 0.001 (3) Solid feedstock. You must calculate, from each ammonia manufacturing unit, the CO2 process emissions from solid feedstock according to equation G–3 to this section: (Eq. G-3) * 0.001 CCn = Carbon content of the solid feedstock, for month n (kg C per kg of feedstock), determined according to § 98.74(c). 44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 = Conversion factor from kg to metric tons. n = Number of month. (4) CO2 process emissions. You must calculate the annual CO2 process emissions at each ammonia manufacturing unit according to equation G–4 to this section: lotter on DSK11XQN23PROD with RULES2 (Eq. G--4) Where: CO2 = Annual CO2 process emissions from each ammonia manufacturing unit (metric tons). CO2,p = Annual CO2 process emissions arising from feedstock consumption based on feedstock type ‘‘p’’ (metric VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 tons/yr) as calculated in paragraphs (b)(1) through (3) of this section. p = Index for feedstock type; 1 indicates gaseous feedstock; 2 indicates liquid feedstock; and 3 indicates solid feedstock. * PO 00000 * * Frm 00104 * Fmt 4701 18. Amend § 98.76 by revising the introductory text and paragraphs (b)(1) and (13) and adding paragraph (b)(16) to read as follows: ■ * Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.006</GPH> § 98.72 ER25AP24.005</GPH> 16. Amend § 98.72 by revising paragraph (a) to read as follows: ■ ER25AP24.004</GPH> Subpart G—Ammonia Manufacturing ammonia manufacturing unit using the procedures in either paragraph (a) or (b) of this section. * * * * * (b) Calculate and report under this subpart process CO2 emissions using the procedures in paragraphs (b)(1) through (4) of this section, as applicable. (1) Gaseous feedstock. You must calculate, from each ammonia manufacturing unit, the CO2 process emissions from gaseous feedstock according to equation G–1 to this section: ER25AP24.003</GPH> (36) Fuel-specific carbon based Ffactor per fuel (scf CO2/mmBtu) (equation C–13 to § 98.33). (37) Moisture content used to calculate the wood and wood residuals wet basis HHV (percent), if applicable (equations C–1 and C–8 to § 98.33). Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations § 98.76 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing unit. * * * * * (b) * * * (1) Annual CO2 process emissions (metric tons) for each ammonia manufacturing unit. * * * * * (13) Annual amount of CO2 (metric tons) collected from ammonia production and consumed on site for urea production and the method used to determine the CO2 consumed in urea production. * * * * * (16) Annual quantity of excess hydrogen produced that is not consumed through the production of ammonia (metric tons). Subpart H—Cement Production ■ 19. Amend § 98.83 by: 31905 a. Revising paragraph (d)(1); ■ b. Revising parameters ‘‘CKDCaO’’ and ‘‘CKDMgO’’ of equation H–4 in paragraph (d)(2)(ii)(A); and ■ c. Revising paragraph (d)(3). The revisions read as follows: ■ § 98.83 Calculating GHG emissions. * * * * * (d) * * * (1) Calculate CO2 process emissions from all kilns at the facility using equation H–1 to this section: (Eq. H-1) = * * * * 20. Amend § 98.86 by adding paragraphs (a)(4) through (8) and (b)(19) through (28) to read as follows: ■ § 98.86 Data reporting requirements. lotter on DSK11XQN23PROD with RULES2 * * * * * (a) * * * (4) Annual arithmetic average of total CaO content of clinker at the facility, wt-fraction. (5) Annual arithmetic average of noncalcined CaO content of clinker at the facility, wt-fraction. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 * CKDncCaO = Quarterly non-calcined CaO content of CKD not recycled to the kiln, wt-fraction. * M [ Li=1 rm Where: rm = The amount of raw material i consumed annually from kiln m, tons/yr (dry basis) or the amount of raw kiln feed consumed annually from kiln m, tons/yr (dry basis). CO2,rm,m = Annual CO2 emissions from raw materials from kiln m. TOCrm = Organic carbon content of raw material i from kiln m or organic carbon content of combined raw kiln feed (dry basis) from kiln m, as determined in § 98.84(c) or using a default factor of 0.2 percent of total raw material weight. M = Number of raw materials or 1 if calculating emissions based on combined raw kiln feed. 44/12 = Ratio of molecular weights, CO2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. * (2) * * * (ii) * * * (A) * * * * * * * 44 * * * * (3) CO2 emissions from raw materials from each kiln. Calculate CO2 emissions from raw materials using equation H–5 to this section: 2000] (Eq. H-5) * TOCrm * 12 * 2205 (6) Annual arithmetic average of total MgO content of clinker at the facility, wt-fraction. (7) Annual arithmetic average of noncalcined MgO content of clinker at the facility, wt-fraction. (8) Annual facility CKD not recycled to the kiln(s), tons. (b) * * * (19) Annual arithmetic average of total CaO content of clinker at the facility, wt-fraction. (20) Annual arithmetic average of non-calcined CaO content of clinker at the facility, wt-fraction. (21) Annual arithmetic average of total MgO content of clinker at the facility, wt-fraction. (22) Annual arithmetic average of non-calcined MgO content of clinker at the facility, wt-fraction. (23) Annual arithmetic average of total CaO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (24) Annual arithmetic average of non-calcined CaO content of CKD not recycled to the kiln(s) at the facility, wtfraction. (25) Annual arithmetic average of total MgO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (26) Annual arithmetic average of non-calcined MgO content of CKD not PO 00000 CKDncMgO = Quarterly non-calcined MgO content of CKD not recycled to the kiln, wt-fraction. Frm 00105 Fmt 4701 Sfmt 4700 recycled to the kiln(s) at the facility, wtfraction. (27) Annual facility CKD not recycled to the kiln(s), tons. (28) The amount of raw kiln feed consumed annually at the facility, tons (dry basis). Subpart I—Electronics Manufacturing 21. Revise and republish § 98.91 to read as follows: ■ § 98.91 Reporting threshold. (a) You must report GHG emissions under this subpart if electronics manufacturing production processes, as defined in § 98.90, are performed at your facility and your facility meets the requirements of either § 98.2(a)(1) or (2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in § 98.2(a)(2), follow the requirements of § 98.2(b), with one exception. Rather than using the calculation methodologies in § 98.93 to calculate emissions from electronics manufacturing production processes, calculate emissions of each fluorinated GHG from electronics manufacturing production processes by using paragraph (a)(1), (2), or (3) of this section, as appropriate, and then sum E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.008</GPH> CO2 rm,m k = Total number of kilns at a cement manufacturing facility. ER25AP24.007</GPH> Where: CO2 CMF = Annual process emissions of CO2 from cement manufacturing, metric tons. CO2 Cli,m = Total annual emissions of CO2 from clinker production from kiln m, metric tons. CO2 rm,m = Total annual emissions of CO2 from raw materials from kiln m, metric tons. 31906 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations the emissions of each fluorinated GHG and account for fluorinated heat transfer fluid emissions by using paragraph (a)(4) of this section. (1) If you manufacture semiconductors or MEMS you must calculate annual production process emissions resulting from the use of each input gas for threshold applicability purposes using either the default emission factors shown in table I–1 to this subpart and equation I–1A to this section, or the consumption of each input gas, the default emission factors shown in table I–2 to this subpart, and equation I–1B to this section. (Eq. I-lA) Where: Ei = Annual production process emissions of gas i for threshold applicability purposes (metric tons CO2e). S = 100 percent of annual manufacturing capacity of a facility as calculated using equation I–5 to this section (m2). EFi = Emission factor for gas i (kg/m2) shown in table I–1 to this subpart. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. 0.001 = Conversion factor from kg to metric tons. i = Emitted gas. Where: Ei = Annual production process emissions resulting from the use of input gas i for threshold applicability purposes (metric tons CO2e). Ci = Annual GHG (input gas i) purchases or consumption (kg). Only gases that are used in semiconductor or MEMS manufacturing processes listed at § 98.90(a)(1) through (4) must be considered for threshold applicability purposes. (1–Ui), BCF4, and BC2F6 = Default emission factors for the gas consumption-based threshold applicability determination listed in table I–2 to this subpart. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. 0.001 = Conversion factor from kg to metric tons. i = Input gas. process emissions resulting from the use of each input gas for threshold applicability purposes using either the default emission factors shown in table I–1 to this subpart and equation I–2A to this section or the consumption of each input gas, the default emission factors shown in table I–2 to this subpart, and equation I–2B to this section. (2) If you manufacture LCDs, you must calculate annual production considered for threshold applicability purposes. (1–Ui), BCF4, and BC2F6 = Default emission factors for the gas consumption-based threshold applicability determination listed in table I–2 to this subpart. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. 0.001 = Conversion factor from kg to metric tons. i = Input gas. (3) If you manufacture PVs, you must calculate annual production process emissions resulting from the use of each input gas i for threshold applicability purposes using gas-appropriate GWP values shown in table A–1 to subpart A of this part, the default emission factors shown in table I–2 to this subpart, and equation I–3 to this section. Where: Ei = Annual production process emissions resulting from the use of input gas i for threshold applicability purposes (metric tons CO2e). Ci = Annual fluorinated GHG (input gas i) purchases or consumption (kg). Only gases that are used in PV manufacturing processes listed at § 98.90(a)(1) through (4) must be considered for threshold applicability purposes. (1 – Ui), BCF4, and BC2F6 = Default emission factors for the gas consumption-based threshold applicability determination listed in table I–2 to this subpart. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. 0.001 = Conversion factor from kg to metric tons. i = Input gas. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00106 Fmt 4701 Sfmt 4700 (4) You must calculate total annual production process emissions for threshold applicability purposes using equation I–4 to this section. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.013</GPH> Where: Ei = Annual production process emissions resulting from the use of input gas i for threshold applicability purposes (metric tons CO2e). Ci = Annual GHG (input gas i) purchases or consumption (kg). Only gases that are used in LCD manufacturing processes listed at § 98.90(a)(1) through (4) must be ER25AP24.012</GPH> GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. 0.000001 = Conversion factor from g to metric tons. i = Emitted gas. ER25AP24.011</GPH> S = 100 percent of annual manufacturing capacity of a facility as calculated using equation I–5 to this section (m2). EFi = Emission factor for gas i (g/m2). ER25AP24.010</GPH> Where: Ei = Annual production process emissions of gas i for threshold applicability purposes (metric tons CO2e). ER25AP24.009</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. I-2A) Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31907 (Eq. I--4) Where: ET = Annual production process emissions of all fluorinated GHGs for threshold applicability purposes (metric tons CO2e). d = Factor accounting for fluorinated heat transfer fluid emissions, estimated as 10 percent of total annual production process emissions at a semiconductor facility. Set equal to 1.1 when equation I–4 to this section is used to calculate total annual production process emissions from semiconductor manufacturing. Set equal to 1 when equation I–4 to this section is used to calculate total annual production process emissions from MEMS, LCD, or PV manufacturing. Ei = Annual production process emissions of gas i for threshold applicability purposes (metric tons CO2e), as calculated in equations I–1a, I–1b, I–2a, I–2b, or I–3 to this section. i = Emitted gas. (b) You must calculate annual manufacturing capacity of a facility using equation I–5 to this section. s = L..x "'12wX (Eq. I-5) Where: S = 100 percent of annual manufacturing capacity of a facility (m2). Wx = Maximum substrate starts of fab f in month x (m2 per month). x = Month. 22. Amend § 98.92 by revising paragraph (a) introductory text to read as follows: 23. Amend § 98.93 by: a. Revising paragraph (a); b. Revising the introductory text of paragraph (e); ■ c. Revising parameters ‘‘UTij’’ and ‘‘Tdijp’’ of equation I–15 in paragraph (g); and ■ d. Revising paragraphs (h)(1) and (i). The revisions read as follows: § 98.92 § 98.93 ■ ■ ■ ■ GHGs to report. (a) You must report emissions of fluorinated GHGs (as defined in § 98.6), N2O, and fluorinated heat transfer fluids (as defined in § 98.6). The fluorinated GHGs and fluorinated heat transfer fluids that are emitted from electronics manufacturing production processes include, but are not limited to, those listed in table I–21 to this subpart. You must individually report, as appropriate: * * * * * Calculating GHG emissions. (a) You must calculate total annual emissions of each fluorinated GHG emitted by electronics manufacturing production processes from each fab (as defined in § 98.98) at your facility, including each input gas and each byproduct gas. You must use either default gas utilization rates and by-product formations rates according to the procedures in paragraph (a)(1), (2), (6), or (7) of this section, as appropriate, or the stack test method according to paragraph (i) of this section, to calculate emissions of each input gas and each by-product gas. (1) If you manufacture semiconductors, you must adhere to the procedures in paragraphs (a)(1)(i) through (iii) of this section. You must calculate annual emissions of each input gas and of each by-product gas using equations I–6, I–7, and I–9 to this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab’s annual consumption for that specific gas as calculated in equation I–11 to this section, plus any by-product emissions of that gas calculated under paragraph (a) of this section. (Eq. I-6) Where: ProcesstypeBEk = Annual emissions of byproduct gas k from the processes type on a fab basis (metric tons). BEkij = Annual emissions of by-product gas k formed from input gas i used for process sub-type or process type j as calculated in equation I–8B to this section (metric tons). VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (Eq. I-7) N = The total number of process sub-types j that depends on the electronics manufacturing fab and emission calculation methodology. If BEkij is calculated for a process type j in equation I–8B to this section, N = 1. i = Input gas. j = Process sub-type, or process type. k = By-product gas. PO 00000 Frm 00107 Fmt 4701 Sfmt 4700 (i) You must calculate annual fablevel emissions of each fluorinated GHG used for the plasma etching/wafer cleaning process type using default utilization and by-product formation rates as shown in table I–3 or I–4 to this subpart, and by using equations I–8A and I–8B to this section. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.017</GPH> = If!, 1 Li BEkii ER25AP24.016</GPH> lotter on DSK11XQN23PROD with RULES2 ProcesstypeBEk manufacturing fab and emission calculation methodology. If Eij is calculated for a process type j in equation I–8A to this section, N = 1. i = Input gas. j = Process sub-type or process type. ER25AP24.015</GPH> Eij = Annual emissions of input gas i from process sub-type or process type j as calculated in equation I–8A to this section (metric tons). N = The total number of process sub-types j that depends on the electronics ER25AP24.014</GPH> Where: ProcesstypeEi = Annual emissions of input gas i from the process type on a fab basis (metric tons). 31908 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (Eq. I-8A) Where: Eij = Annual emissions of input gas i from process sub-type or process type j, on a fab basis (metric tons). Cij = Amount of input gas i consumed for process sub-type or process type j, as calculated in equation I–13 to this section, on a fab basis (kg). Uij = Process utilization rate for input gas i for process sub-type or process type j (expressed as a decimal fraction). aij = Fraction of input gas i used in process sub-type or process type j with abatement systems, on a fab basis (expressed as a decimal fraction). dij = Fraction of input gas i destroyed or removed when fed into abatement systems by process tools where process sub-type, or process type j is used, on a fab basis, calculated by taking the tool weighted average of the claimed DREs for input gas i on tools that use process type or process sub-type j (expressed as a decimal fraction). This is zero unless the facility adheres to the requirements in § 98.94(f). UTij = The average uptime factor of all abatement systems connected to process tools in the fab using input gas i in process sub-type or process type j, as calculated in equation I–15 to this section, on a fab basis (expressed as a decimal fraction). 0.001 = Conversion factor from kg to metric tons. i = Input gas. j = Process sub-type or process type. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 sub-type or process type j, on a fab basis (expressed as a decimal fraction). For this equation, UTkij is assumed to be equal to UTij as calculated in equation I– 15 to this section. 0.001 = Conversion factor from kg to metric tons. i = Input gas. j = Process sub-type or process type. k = By-product gas. (ii) You must calculate annual fablevel emissions of each fluorinated GHG used for each of the process sub-types associated with the chamber cleaning process type, including in-situ plasma chamber clean, remote plasma chamber clean, and in-situ thermal chamber clean, using default utilization and byproduct formation rates as shown in table I–3 or I–4 to this subpart, and by using equations I–8A and I–8B to this section. (iii) If default values are not available for a particular input gas and process type or sub-type combination in tables I–3 or I–4, you must follow the procedures in paragraph (a)(6) of this section. (2) If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use § 98.3(a)(1) to calculate annual fab-level emissions for those processes. For all other tools and processes used to manufacture MEMs, LCD and PV, you must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching and chamber cleaning process types using default utilization and by-product formation rates as shown in table I–5, I– 6, or I–7 to this subpart, as appropriate, and by using equations I–8A and I–8B to this section. If default values are not available for a particular input gas and process type or sub-type combination in tables I–5, I–6, or I–7 to this subpart, you must follow the procedures in PO 00000 Frm 00108 Fmt 4701 Sfmt 4700 paragraph (a)(6) of this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab’s annual consumption for that specific gas as calculated in equation I– 11 to this section, plus any by-product emissions of that gas calculated under this paragraph (a). (3)–(5) [Reserved] (6) If you are required, or elect, to perform calculations using default emission factors for gas utilization and by-product formation rates according to the procedures in paragraph (a)(1) or (2) of this section, and default values are not available for a particular input gas and process type or sub-type combination in tables I–3, I–4, I–5, I–6, or I–7 to this subpart, you must use a utilization rate (Uij) of 0.2 (i.e., a 1–Uij of 0.8) and by-product formation rates of 0.15 for CF4 and 0.05 for C2F6 and use equations I–8A and I–8B to this section. (7) If your fab employs hydrocarbonfuel-based combustion emissions control systems (HC fuel CECS), including, but not limited to, abatement systems as defined at § 98.98, that were purchased and installed on or after January 1, 2025, to control emissions from tools that use either NF3 in remote plasma cleaning processes or F2 as an input gas in any process type or subtype, you must calculate the amount CF4 produced within and emitted from such systems using equation I–9 to this section using default utilization and byproduct formation rates as shown in table I–3 or I–4 to this subpart. A HC fuel CECS is assumed not to form CF4 from F2 if the electronics manufacturer can certify that the rate of conversion from F2 to CF4 is <0.1% for that HC fuel CECS. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.019</GPH> Where: BEkij = Annual emissions of by-product gas k formed from input gas i from process sub-type or process type j, on a fab basis (metric tons). Bkij = By-product formation rate of gas k created as a by-product per amount of input gas i (kg) consumed by process sub-type or process type j (kg). If all input gases consumed by a chamber cleaning process sub-type are non-carbon containing input gases, this is zero when the combination of the non-carbon containing input gas and chamber cleaning process sub-type is never used to clean chamber walls on equipment that process carbon-containing films during the year (e.g., when NF3 is used in remote plasma cleaning processes to only clean chambers that never process carbon-containing films during the year). If all input gases consumed by an etching and wafer cleaning process sub-type are non-carbon containing input gases, this is zero when the combination of the noncarbon containing input gas and etching and wafer cleaning process sub-type is never used to etch or wafer clean carboncontaining films during the year. Cij = Amount of input gas i consumed for process sub-type, or process type j, as calculated in equation I–13 to this section, on a fab basis (kg). akij = Fraction of input gas i used for process sub-type, or process type j with abatement systems, on a fab basis (expressed as a decimal fraction). dkij = Fraction of by-product gas k destroyed or removed in when fed into abatement systems by process tools where process sub-type or process type j is used, on a fab basis, calculated by taking the tool weighted average of the claimed DREs for by-product gas k on tools that use input gas i in process type or process sub-type j (expressed as a decimal fraction). This is zero unless the facility adheres to the requirements in § 98.94(f). UTkij = The average uptime factor of all abatement systems connected to process tools in the fab emitting by-product gas k, formed from input gas i in process ER25AP24.018</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. I-8B) Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31909 El·s -- VerDate Sep<11>2014 19:27 Apr 24, 2024 MlAT vv,1· be equal to UTNF3,RPC as calculated in equation I–15 to this section. j = Process type or sub-type. * * * * * (e) You must calculate the amount of input gas i consumed, on a fab basis, for each process sub-type or process type j, using equation I–13 to this section. Where a gas supply system serves more than one fab, equation I–13 to this section is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c). If you elect to calculate emissions using the stack test method in paragraph (i) of this section and to use this paragraph (e) to calculate the fraction each fluorinated input gas i exhausted from tools with abatement systems and the fraction of each byproduct gas k exhausted from tools with abatement systems, you may substitute ‘‘The set of tools with abatement systems’’ for ‘‘Process sub-type or process type’’ in the definition of ‘‘j’’ in equation I–13 to this section. * * * * * (g) * * * UTij = The average uptime factor of all abatement systems connected to process tools in the fab using input gas i in process sub-type or process type j (expressed as a decimal fraction). The average uptime factor may be set to one (1) if all the abatement systems for the relevant input gas i and process sub-type or type j are interlocked with all the tools using input gas i in process sub-type or type j and feeding the abatement systems such that no gas can flow to the tools if the abatement systems are not in operational mode. Tdijp = The total time, in minutes, that abatement system p, connected to process tool(s) in the fab using input gas i in process sub-type or process type j, is not in operational mode, as defined in § 98.98, when at least one of the tools connected to abatement system p is in operation. If your fab uses redundant abatement systems, you may account for Tdijp as specified in § 98.94(f)(4)(vi). * * * * * (h) * * * (1) If you use a fluorinated chemical both as a fluorinated heat transfer fluid and in other applications, you may 1 * Qs * -sv * -101 3 * Jkt 262001 PO 00000 Frm 00109 "°N Xism L....m-1-10 9 Fmt 4701 * calculate and report either emissions from all applications or from only those specified in the definition of fluorinated heat transfer fluids in § 98.6. * * * * * (i) Stack test method. As an alternative to the default emission factor method in paragraph (a) of this section, you may calculate fab-level fluorinated GHG emissions using fab-specific emission factors developed from stack testing. In this case, you must comply with the stack test method specified in paragraph (i)(3) of this section. (1)–(2) [Reserved] (3) Stack system stack test method. For each stack system in the fab, measure the emissions of each fluorinated GHG from the stack system by conducting an emission test. In addition, measure the fab-specific consumption of each fluorinated GHG by the tools that are vented to the stack systems tested. Measure emissions and consumption of each fluorinated GHG as specified in § 98.94(j). Develop fabspecific emission factors and calculate fab-level fluorinated GHG emissions using the procedures specified in paragraphs (i)(3)(i) through (viii) of this section. All emissions test data and procedures used in developing emission factors must be documented and recorded according to § 98.97. (i) You must measure the fab-specific fluorinated GHG consumption of the tools that are vented to the stack systems during the emission test as specified in § 98.94(j)(3). Calculate the consumption for each fluorinated GHG for the test period. (ii) You must calculate the emissions of each fluorinated GHG consumed as an input gas using equation I–17 to this section and each fluorinated GHG formed as a by-product gas using equation I–18 to this section and the procedures specified in paragraphs (i)(3)(ii)(A) through (E) of this section. If a stack system is comprised of multiple stacks, you must sum the emissions from each stack in the stack system when using equation I–17 or equation I– 18 to this section. A utm Sfmt 4725 E:\FR\FM\25APR2.SGM (Eq. I-17) 25APR2 ER25AP24.021</GPH> Where: EABCF4 = Emissions of CF4 from HC fuel CECS when direct reaction between hydrocarbon fuel and F2 is not certified not to occur by the emissions control system manufacturer or electronics manufacturer, kg. CF2,j = Amount of F2 consumed for process type or sub-type j, as calculated in equation I–13 to this section, on a fab basis (kg). UF2,j = Process utilization rate for F2 for process type or sub-type j (expressed as a decimal fraction). aF2,j = Within process sub-type or process type j, fraction of F2 used in process tools with HC fuel CECS that are not certified not to form CF4, on a fab basis, where the numerator is the number of tools that are equipped with HC fuel CECS that are not certified not to form CF4 that use F2 in process type j and the denominator is the total number of tools in the fab that use F2 in process type j (expressed as a decimal fraction). UTF2,j = The average uptime factor of all HC fuel CECS connected to process tools in the fab using F2 in process sub-type or process type j (expressed as a decimal fraction). ABCF4,F2 = Mass fraction of F2 in process exhaust gas that is converted into CF4 by direct reaction with hydrocarbon fuel in a HC fuel CECS. The default value of ABCF4,F2 = 0.116. CNF3,RPC = Amount of NF3 consumed in remote plasma cleaning processes, as calculated in equation I–13 to this section, on a fab basis (kg). BF2,NF3 = By-product formation rate of F2 created as a by-product per amount of NF3 (kg) consumed in remote plasma cleaning processes (kg). aNF3,RPC = Within remote plasma cleaning processes, fraction of NF3 used in process tools with HC fuel CECS that are not certified not to form CF4, where the numerator is the number of tools running remote plasma cleaning processes that are equipped with HC fuel CECS that are not certified not to form CF4 that use NF3 and the denominator is the total number of tools that run remote plasma clean processes in the fab that use NF3 (expressed as decimal fraction). UTNF3,RPC,F2 = The average uptime factor of all HC fuel CECS connected to process tools in the fab emitting by-product gas F2, formed from input gas NF3 in remote plasma cleaning processes, on a fab basis (expressed as a decimal fraction). For this equation, UTNF3,RPC,F2 is assumed to ER25AP24.020</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. I-9) 31910 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Where: Eis = Total fluorinated GHG input gas i, emitted from stack system s, during the sampling period (kg). Xism = Average concentration of fluorinated GHG input gas i in stack system s, during the time interval m (ppbv). MWi = Molecular weight of fluorinated GHG input gas i (g/g-mole). Eks -- MHT vv 1k Qs = Flow rate of the stack system s, during the sampling period (m3/min). SV = Standard molar volume of gas (0.0240 m3/g-mole at 68 °F and 1 atm). Dtm = Length of time interval m (minutes). Each time interval in the FTIR sampling period must be less than or equal to 60 minutes (for example an 8 hour sampling 1 1 * Qs * -sv * -10 3 * Where: Eks = Total fluorinated GHG by-product gas k, emitted from stack system s, during the sampling period (kg). Xks = Average concentration of fluorinated GHG by-product gas k in stack system s, during the time interval m (ppbv). MWk = Molecular weight of the fluorinated GHG by-product gas k (g/g-mole). Qs = Flow rate of the stack system s, during the sampling period (m3/min). SV = Standard molar volume of gas (0.0240 m3/g-mole at 68 °F and 1 atm). Dtm = Length of time interval m (minutes). Each time interval in the FTIR sampling period must be less than or equal to 60 minutes (for example an 8 hour sampling period would consist of at least 8 time intervals). 1/103 = Conversion factor (1 kilogram/1,000 grams). k = Fluorinated GHG by-product gas. s = Stack system. N = Total number of time intervals m in sampling period. m = Time interval. (A) If a fluorinated GHG is consumed during the sampling period, but emissions are not detected, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of ‘‘Xism’’ in equation I–17 to this section. (B) If a fluorinated GHG is consumed during the sampling period and detected intermittently during the sampling period, use the detected concentration for the value of ‘‘Xism’’ in equation I–17 to this section when "1N Xksm L..m-1-10 9 * period would consist of at least 8 time intervals). 1/103 = Conversion factor (1 kilogram/1,000 grams). i = Fluorinated GHG input gas. s = Stack system. N = Total number of time intervals m in sampling period. m = Time interval. (Eq. I-18) A L.ltm available and use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of ‘‘Xism’’ when the fluorinated GHG is not detected. (C) If an expected or possible byproduct, as listed in table I–17 to this subpart, is detected intermittently during the sampling period, use the measured concentration for ‘‘Xksm’’ in equation I–18 to this section when available and use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of ‘‘Xksm’’ when the fluorinated GHG is not detected. (D) If a fluorinated GHG is not consumed during the sampling period and is an expected by-product gas as listed in table I–17 to this subpart and is not detected during the sampling period, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of ‘‘Xksm’’ in equation I–18 to this section. (E) If a fluorinated GHG is not consumed during the sampling period and is a possible by-product gas as listed in table I–17 to this subpart, and is not detected during the sampling period, then assume zero emissions for that fluorinated GHG for the tested stack system. (iii) You must calculate a fab-specific emission factor for each fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted per kg of input gas i consumed) in the tools that vent to stack systems, as applicable, using equations I–19A and I–19B to this section or equations I–19A and I–19C to this section. Use equation I–19A to this section to calculate the controlled emissions for each carbon-containing fluorinated GHG that would result during the sampling period if the utilization rate for the input gas were equal to 0.2 (Eimax,f). If SsEi,s (the total measured emissions of the fluorinated GHG across all stack systems, calculated based on the results of equation I–17 to this section) is less than or equal to Eimax,f calculated in equation I–19A to this section, use equation I–19B to this section to calculate the emission factor for that fluorinated GHG. If SsEi,s is larger than the Eimax,f calculated in equation I–19A to this section, use equation I–19C to this section to calculate the emission factor and treat the difference between the total measured emissions SsEi,s and the maximum expected controlled emissions Eimax,f as a by-product of the other input gases, using equation I–20 to this section. For all fluorinated GHGs that do not contain carbon, use equation I–19B to this section to calculate the emission factor for that fluorinated GHG. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 UTf = The total uptime of all abatement systems for fab f, during the sampling period, as calculated in equation I–23 to this section (expressed as decimal fraction). If the stack system does not have abatement systems on the tools vented to the stack system, the value of this parameter is zero. aif = Fraction of input gas i emitted from tools with abatement systems in fab f (expressed as a decimal fraction), as PO 00000 Frm 00110 Fmt 4701 Sfmt 4700 calculated in equation I–24C to this section. dif = Fraction of fluorinated GHG input gas i destroyed or removed when fed into abatement systems by process tools in fab f, as calculated in equation I–24A to this section (expressed as decimal fraction). f = Fab. i = Fluorinated GHG input gas. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.023</GPH> Where: Eimax,f = Maximum expected controlled emissions of gas i from its use an input gas during the stack testing period, from fab f (max kg emitted). Activityif = Consumption of fluorinated GHG input gas i, for fab f, in the tools vented to the stack systems being tested, during the sampling period, as determined following the procedures specified in § 98.94(j)(3) (kg consumed). ER25AP24.022</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. I-19A) Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31911 (Eq. I-19B) Where: EFif = Emission factor for fluorinated GHG input gas i, from fab f, representing 100 percent abatement system uptime (kg emitted/kg input gas consumed). Eis = Mass emission of fluorinated GHG input gas i from stack system s during the sampling period (kg emitted). Activityif = Consumption of fluorinated GHG input gas i, for fab f during the sampling period, as determined following the procedures specified in § 98.94(j)(3) (kg consumed). UTf = The total uptime of all abatement systems for fab f, during the sampling period, as calculated in equation I–23 to this section (expressed as decimal fraction). If the stack system does not have abatement systems on the tools vented to the stack system, the value of this parameter is zero. aif = Fraction of fluorinated GHG input gas i exhausted from tools with abatement systems in fab f (expressed as a decimal fraction), as calculated in equation I–24C to this section. dif = Fraction of fluorinated GHG input gas i destroyed or removed when fed into abatement systems by process tools in fab f, as calculated in equation I–24A to this section (expressed as decimal fraction). If the stack system does not have abatement systems on the tools vented to the stack system, the value of this parameter is zero. f = Fab. i = Fluorinated GHG input gas. s = Stack system. (Eq. I-19C) dif = Fraction of fluorinated GHG input gas i destroyed or removed when fed into abatement systems by process tools in fab f, as calculated in equation I–24A to this section (expressed as decimal fraction). f = Fab. i = Fluorinated GHG input gas. (iv) You must calculate a fab-specific emission factor for each fluorinated Ls(Eks) ( LiAct1v1tyif* UTf+( Where: EFkf = Emission factor for fluorinated GHG by-product gas k, from fab f, representing 100 percent abatement system uptime (kg emitted/kg of all input gases consumed in tools vented to stack systems). Eks = Mass emission of fluorinated GHG byproduct gas k, emitted from stack system s, during the sampling period (kg emitted). Activityif = Consumption of fluorinated GHG input gas i for fab f in tools vented to stack systems during the sampling l- ( 1-UTf ct akif* kif )) (Eq. I-20) ) period as determined following the procedures specified in § 98.94(j)(3) (kg consumed). UTf = The total uptime of all abatement systems for fab f, during the sampling period, as calculated in equation I–23 to this section (expressed as decimal fraction). akif = Fraction of by-product k emitted from tools using input gas i with abatement systems in fab f (expressed as a decimal fraction), as calculated using equation I– 24D to this section. dkif = Fraction of fluorinated GHG by-product gas k generated from input gas i destroyed or removed when fed into abatement systems by process tools in fab f, as calculated in equation I–24B to this section (expressed as decimal fraction). f = Fab. i = Fluorinated GHG input gas. k = Fluorinated GHG by-product gas. s = Stack system. (v) You must calculate annual fablevel emissions of each fluorinated GHG consumed using equation I–21 to this section. lotter on DSK11XQN23PROD with RULES2 (Eq. I-21) Where: Eif = Annual emissions of fluorinated GHG input gas i (kg/year) from the stack systems for fab f. EFif = Emission factor for fluorinated GHG input gas i emitted from fab f, as calculated in equation I–19 to this section (kg emitted/kg input gas consumed). Cif = Total consumption of fluorinated GHG input gas i in tools that are vented to stack systems, for fab f, for the reporting VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 year, as calculated using equation I–13 to this section (kg/year). UTf = The total uptime of all abatement systems for fab f, during the reporting year, as calculated using equation I–23 to this section (expressed as a decimal fraction). aif = Fraction of fluorinated GHG input gas i emitted from tools with abatement systems in fab f (expressed as a decimal fraction), as calculated using equation I– 24C or I–24D to this section. PO 00000 Frm 00111 Fmt 4701 Sfmt 4700 dif = Fraction of fluorinated GHG input gas i destroyed or removed when fed into abatement systems by process tools in fab f that are included in the stack testing option, as calculated in equation I–24A to this section (expressed as decimal fraction). f = Fab. i = Fluorinated GHG input gas. (vi) You must calculate annual fablevel emissions of each fluorinated GHG E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.027</GPH> . . ER25AP24.026</GPH> kf - ER25AP24.025</GPH> _ EF GHG formed as a by-product (in kg of fluorinated GHG per kg of total fluorinated GHG consumed) in the tools vented to stack systems, as applicable, using equation I–20 to this section. When calculating the by-product emission factor for an input gas for which SsEi,s equals or exceeds Eimax,f, exclude the consumption of that input gas from the term ‘‘S(Activityif).’’ ER25AP24.024</GPH> EFif = Emission factor for input gas i, from fab f, representing a 20-percent utilization rate and a 100-percent abatement system uptime (kg emitted/kg input gas consumed). aif = Fraction of input gas i emitted from tools with abatement systems in fab f (expressed as a decimal fraction), as calculated in equation I–24C to this section. 31912 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations by-product formed using equation I–22 to this section. (Eq. I-22) D lotter on DSK11XQN23PROD with RULES2 determining the amount of tool operating time, you may assume that tools that were installed for the whole of the year were operated for 525,600 minutes per year. For tools that were installed or uninstalled during the year, you must prorate the operating time to account for the days in which the tool was not installed; treat any partial day that a tool was installed as a full day (1,440 minutes) of tool operation. For an abatement system that has more than one connected tool, the tool operating time is 525,600 minutes per year if there was at least one tool installed at all times throughout the year. If you have tools that are idle with no gas flow through the tool, you may calculate total tool time using the actual time that gas is flowing through the tool. f = Fab. Lp(Yi,p"LDREy ni,p,DREy·DREy)+ LDREz DREz-mi,q,DREz if - "' y·1,p •n·1,p,a + m·1,q,a L..p _ p = Abatement system. (viii) When using the stack testing option described in this paragraph (i) and when using more than one DRE for the same input gas i or by-product gas k, you must calculate the weightedaverage fraction of each fluorinated input gas i and each fluorinated byproduct gas k that has more than one DRE and that is destroyed or removed in abatement systems for each fab f, as applicable, by using equation I–24A to this section (for input gases) and equation I–24B to this section (for byproduct gases) and table I–18 to this subpart. If default values are not available in table I–18 for a particular input gas, you must use a value of 10. (Eq. I-24A) Lp(Yk,i,p"LDREy nk,i,p,DREy·DREy)+ LDREz DREz-mk,i,q,DREz ._.. Yk,1,p . •nk,1,p,a · + mk,1,q,a · L..p Where: dif = The average weighted fraction of fluorinated GHG input gas i destroyed or removed when fed into abatement systems by process tools in fab f (expressed as a decimal fraction). dkif = The average weighted fraction of fluorinated GHG by-product gas k generated from input gas i that is destroyed or removed when fed into abatement systems by process tools in fab f (expressed as a decimal fraction). VerDate Sep<11>2014 (Eq. I-23) Lp UT pf D _ kif - (vii) When using the stack testing method described in this paragraph (i), you must calculate abatement system uptime on a fab basis using equation I– 23 to this section. When calculating abatement system uptime for use in equation I–19 and I–20 to this section, you must evaluate the variables ‘‘Tdpf’’ and ‘‘UTpf’’ for the sampling period instead of the reporting year. 19:27 Apr 24, 2024 Jkt 262001 ni,p,DREy = Number of tools that use gas i, that run chamber cleaning process p, and that are equipped with abatement systems for gas i that have the DRE DREy. mi,q,DREz = Number of tools that use gas i, that run etch and/or wafer cleaning processes, and that are equipped with abatement systems for gas i that have the DRE DREz. ni,p,a = Total number of tools that use gas i, run chamber cleaning process type p, PO 00000 Frm 00112 Fmt 4701 Sfmt 4700 (Eq. I-24B) and that are equipped with abatement systems for gas i. mi,q,a = Total number of tools that use gas i, run etch and/or wafer cleaning processes, and that are equipped with abatement systems for gas i. nk,i,p,DREy = Number of tools that use gas i, generate by-product k, that run chamber cleaning process p, and that are equipped with abatement systems for gas i that have the DRE DREy. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.030</GPH> Where: UTf = The average uptime factor for all abatement systems in fab f (expressed as a decimal fraction). The average uptime factor may be set to one (1) if all the abatement systems in fab f are interlocked with all the tools feeding the abatement systems such that no gas can flow to the tools if the abatement systems are not in operational mode. Tdpf = The total time, in minutes, that abatement system p, connected to process tool(s) in fab f, is not in operational mode as defined in § 98.98. If your fab uses redundant abatement systems, you may account for Tdpf as specified in § 98.94(f)(4)(vi). UTpf = Total time, in minutes per year, in which the tool(s) connected at any point during the year to abatement system p, in fab f could be in operation. For LpTdpf f = Fab. i = Fluorinated GHG input gas. k = Fluorinated GHG by-product. ER25AP24.029</GPH> UTf = 1- year as calculated using equation I–23 to this section (expressed as a decimal fraction). akif = Estimate of fraction of fluorinated GHG by-product gas k emitted in fab f from tools using input gas i with abatement systems (expressed as a decimal fraction), as calculated using equation I– 24D to this section. dkif = Fraction of fluorinated GHG by-product k generated from input gas i destroyed or removed when fed into abatement systems by process tools in fab f that are included in the stack testing option, as calculated in equation I–24B to this section (expressed as decimal fraction). ER25AP24.028</GPH> Where: Ekf = Annual emissions of fluorinated GHG by-product gas k (kg/year) from the stack for fab f. EFkf = Emission factor for fluorinated GHG by-product gas k, emitted from fab f, as calculated in equation I–20 to this section (kg emitted/kg of all fluorinated input gases consumed). Cif = Total consumption of fluorinated GHG input gas i in tools that are vented to stack systems, for fab f, for the reporting year, as calculated using equation I–13 to this section. UTf = The total uptime of all abatement systems for fab f, during the reporting Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations = LpYi,p"Ili,p,a+ mi,q,a A . lotter on DSK11XQN23PROD with RULES2 k,1,f 19:27 Apr 24, 2024 processes, and that are equipped with abatement systems for gas i. ni,p = Total number of tools using gas i and running chamber cleaning process subtype p. mi,q = Total number of tools using gas i and running etch and/or wafer cleaning processes. gi,p = Default factor reflecting the ratio of uncontrolled emissions per tool of input gas i from tools running process type p = Lp Yk,i,p"Ilk,i,p,a + mk,i,q,a Jkt 262001 q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. (B) Use paragraph (e) of this section to apportion consumption of gas i either to tools with abatement systems and tools without abatement systems or to each process type or sub-type, as applicable. If you apportion consumption of gas i to each process type or sub-type, calculate the fractions of input gas i and by-product gas k formed from gas i that are exhausted from tools with abatement systems based on the numbers of tools with and without abatement systems within each process type or sub-type. (4) Method to calculate emissions from fluorinated GHGs that are not tested. Calculate emissions from consumption of each intermittent lowuse fluorinated GHG as defined in § 98.98 of this subpart using the default utilization and by-product formation rates provided in table I–11, I–12, I–13, I–14, or I–15 to this subpart, as PO 00000 Frm 00113 Fmt 4701 processes to uncontrolled emissions per tool of input gas i from process tools running process type q processes. p = Chamber cleaning process sub-type. q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. Eq. I-24D ._.. . ·nk,I,. p + mk,i,q L..p Yk,l,p Where: ak,i,f = Fraction of by-product gas k exhausted from tools using input gas i with abatement systems in fab f (expressed as a decimal fraction). nk,i,p,a = Number of tools that exhaust byproduct gas k from input gas i, that run chamber cleaning process p, and that are equipped with abatement systems for gas k. mk,i,q,a = Number of tools that exhaust byproduct gas k from input gas i, that run etch and/or wafer cleaning processes, and that are equipped with abatement systems for gas k. nk,i,p = Total number of tools emitting byproduct k from input gas i and running chamber cleaning process p. mk,i,q = Total number of tools emitting byproduct k from input gas i and running etch and/or wafer cleaning processes. gk,i,p = Default factor reflecting the ratio of uncontrolled emissions per tool of byproduct gas k from input gas i from tools running chamber cleaning process p to uncontrolled emissions per tool of byproduct gas k from input gas i from process tools running etch and/or wafer cleaning processes. p = Chamber cleaning process sub-type. VerDate Sep<11>2014 (Eq. I-24C) ._.. y·!,p •n·p+miq L..p I, , Where: aif = Fraction of fluorinated input gas i exhausted from tools with abatement systems in fab f (expressed as a decimal fraction). ni,p,a = Number of tools that use gas i, that run chamber cleaning process sub-type p, and that are equipped with abatement systems for gas i. mi,q,a = Number of tools that use gas i, that run etch and/or wafer cleaning (ix) When using the stack testing method described in this paragraph (i), you must calculate the fraction each fluorinated input gas i exhausted in fab f from tools with abatement systems and the fraction of each by-product gas k exhausted from tools with abatement systems, as applicable, by following either the procedure set forth in paragraph (i)(3)(ix)(A) of this section or the procedure set forth in paragraph (i)(3)(ix)(B) of this section. (A) Use equation I–24C to this section (for input gases) and equation I–24D to this section (for by-product gases) and table I–18 to this subpart. If default values are not available in table I–18 for a particular input gas, you must use a value of 10. Sfmt 4700 applicable, and by using equations I– 8A, I–8B, I–9, and I–13 to this section. If a fluorinated GHG was not being used during the stack testing and does not meet the definition of intermittent lowuse fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas according to the procedures specified in paragraph (i)(3) of this section. (5) [Reserved] ■ 24. Amend § 98.94 by: ■ a. Revising paragraph (c) introductory text; ■ b. Adding paragraph (e); ■ c. Revising paragraphs (f)(3), (f)(4) introductory text, (f)(4)(iii), (j)(1) introductory text, (j)(1)(i), (j)(3) introductory text, and (j)(5); and ■ d. Removing and reserving paragraphs (j)(6) and (j)(8)(v). The revisions and addition read as follows: E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.032</GPH> A· 1,f gk,i,p = Default factor reflecting the ratio of uncontrolled emissions per tool of input gas i from tools running process sub-type p processes to uncontrolled emissions per tool of input gas i from process tools running process type q processes. DREy = Default or alternative certified DRE for gas i for abatement systems connected to CVD tool. DREz = Default or alternative certified DRE for gas i for abatement systems connected to etching and/or wafer cleaning tool. p = Chamber cleaning process sub-type. q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. f = Fab. i = Fluorinated GHG input gas. ER25AP24.031</GPH> mk,i,q,DREz = Number of tools that use gas i, generate by-product k, that run etch and/ or wafer cleaning processes, and that are equipped with abatement systems for gas i that have the DRE DREz. nk,i,p,a = Total number of tools that use gas i, generate by-product k, run chamber cleaning process type p, and that are equipped with abatement systems for gas i. mk,i,q,a = Total number of tools that use gas i, generate by-product k, run etch and/or wafer cleaning processes, and that are equipped with abatement systems for gas i. gi,p = Default factor reflecting the ratio of uncontrolled emissions per tool of input gas i from tools running process sub-type p processes to uncontrolled emissions per tool of input gas i from process tools running process type q processes. 31913 31914 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations § 98.94 Monitoring and QA/QC requirements. lotter on DSK11XQN23PROD with RULES2 * * * * * (c) You must develop apportioning factors for fluorinated GHG and N2O consumption (including the fraction of gas consumed by process tools connected to abatement systems as in equations I–8A, I–8B, I–9, and I–10 to § 98.93), to use in the equations of this subpart for each input gas i, process sub-type, process type, stack system, and fab as appropriate, using a fabspecific engineering model that is documented in your site GHG Monitoring Plan as required under § 98.3(g)(5). This model must be based on a quantifiable metric, such as wafer passes or wafer starts, or direct measurement of input gas consumption as specified in paragraph (c)(3) of this section. To verify your model, you must demonstrate its precision and accuracy by adhering to the requirements in paragraphs (c)(1) and (2) of this section. * * * * * (e) If you use HC fuel CECS purchased and installed on or after January 1, 2025 to control emissions from tools that use either NF3 as an input gas in remote plasma cleaning processes or F2 as an input gas in any process, and if you use a value less than 1 for either aF2,j or aNF3,RPC in equation I–9 to § 98.93, you must certify and document that the model for each of the systems for which you are claiming that it does not form CF4 from F2 has been tested and verified to produce less than 0.1% CF4 from F2 and that each of the systems is installed, operated, and maintained in accordance with the directions of the HC fuel CECS manufacturer. Hydrocarbon-fuel-based combustion emissions control systems include but are not limited to abatement systems as defined in § 98.98 that are hydrocarbon-fuel-based. The rate of conversion from F2 to CF4 must be measured using a scientifically sound, industry-accepted method that accounts for dilution through the abatement device, such as EPA 430–R–10–003 (incorporated by reference, see § 98.7), adjusted to calculate the rate of conversion from F2 to CF4 rather than the DRE. Either the HC fuel CECS manufacturer or the electronics manufacturer may perform the measurement. The flow rate of F2 into the tested HC fuel CECS may be metered using a calibrated mass flow controller. (f) * * * (3) If you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), you must certify and document that the abatement systems at your facility for which you use default VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 destruction or removal efficiency values are specifically designed for fluorinated GHG or N2O abatement, as applicable, and provide the abatement system manufacturer-verified DRE value that meets (or exceeds) the default destruction or removal efficiency in table I–16 to this subpart for the fluorinated GHG or N2O. For abatement systems purchased and installed on or after January 1, 2025, you must also certify and document that the abatement system has been tested by the abatement system manufacturer based on the methods specified in paragraph (f)(3)(i) of this section and verified to meet (or exceed) the default destruction or removal efficiency in table I–16 for the fluorinated GHG or N2O under worstcase flow conditions as defined in paragraph (f)(3)(ii) of this section. If you use a verified destruction and removal efficiency value that is lower than the default in table I–16 to this subpart in your emissions calculations under § 98.93(a), (b), and/or (i), you must certify and document that the abatement systems at your facility for which you use the verified destruction or removal efficiency values are specifically designed for fluorinated GHG or N2O abatement, as applicable, and provide the abatement system manufacturerverified DRE value that is lower than the default destruction or removal efficiency in table I–16 for the fluorinated GHG or N2O. For abatement systems purchased and installed on or after January 1, 2025, you must also certify and document that the abatement system has been tested by the abatement system manufacturer based on the methods specified in paragraph (f)(3)(i) of this section and verified to meet or exceed the destruction or removal efficiency value used for that fluorinated GHG or N2O under worstcase flow conditions as defined in paragraph (f)(3)(ii) of this section. If you elect to calculate fluorinated GHG emissions using the stack test method under § 98.93(i), you must also certify that you have included and accounted for all abatement systems designed for fluorinated GHG abatement and any respective downtime in your emissions calculations under § 98.93(i)(3). (i) For purposes of paragraph (f)(3) of this section, destruction and removal efficiencies for abatement systems purchased and installed on or after January 1, 2025, must be measured using a scientifically sound, industryaccepted measurement methodology that accounts for dilution through the abatement system, such as EPA 430–R– 10–003 (incorporated by reference, see § 98.7). PO 00000 Frm 00114 Fmt 4701 Sfmt 4700 (ii) Worst-case flow conditions are defined as the highest total fluorinated GHG or N2O flows through each model of emissions control systems (gas by gas and process type by process type across the facility) and the highest total flow scenarios (with N2 dilution accounted for) across the facility during which the abatement system is claimed to be in operational mode. (4) If you calculate and report controlled emissions using neither the default destruction or removal efficiency values in table I–16 to this subpart nor an abatement system manufacturer-verified lower destruction or removal efficiency value per paragraph (f)(3) of this section, you must use an average of properly measured destruction or removal efficiencies for each gas and process sub-type or process type combination, as applicable, determined in accordance with procedures in paragraphs (f)(4)(i) through (vi) of this section. This includes situations in which your fab employs abatement systems not specifically designed for fluorinated GHG or N2O abatement or for which your fab operates abatement systems outside the range of parameters specified in the documentation supporting the certified DRE and you elect to reflect emission reductions due to these systems. You must not use a default value from table I–16 to this subpart for any abatement system not specifically designed for fluorinated GHG and N2O abatement, for any abatement system not certified to meet the default value from table I–16, or for any gas and process type combination for which you have measured the destruction or removal efficiency according to the requirements of paragraphs (f)(4)(i) through (vi) of this section. * * * * * (iii) If you elect to take credit for abatement system destruction or removal efficiency before completing testing on 20 percent of the abatement systems for that gas and process subtype or process type combination, as applicable, you must use default destruction or removal efficiencies or a verified destruction or removal efficiency, if verified at a lower value, for a gas and process type combination. You must not use a default value from table I–16 to this subpart for any abatement system not specifically designed for fluorinated GHG and N2O abatement, and must not take credit for abatement system destruction or removal efficiency before completing testing on 20 percent of the abatement systems for that gas and process sub- E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations type or process type combination, as applicable. Following testing on 20 percent of abatement systems for that gas and process sub-type or process type combination, you must calculate the average destruction or removal efficiency as the arithmetic mean of all test results for that gas and process subtype or process type combination, until you have tested at least 30 percent of all abatement systems for each gas and process sub-type or process type combination. After testing at least 30 percent of all systems for a gas and process sub-type or process type combination, you must use the arithmetic mean of the most recent 30 percent of systems tested as the average destruction or removal efficiency. You may include results of testing conducted on or after January 1, 2011 for use in determining the site-specific destruction or removal efficiency for a given gas and process sub-type or process type combination if the testing was conducted in accordance with the requirements of paragraph (f)(4)(i) of this section. * * * * * (j) * * * (1) Stack system testing. Conduct an emissions test for each stack system according to the procedures in paragraphs (j)(1)(i) through (iv) of this section. (i) You must conduct an emission test during which the fab is operating at a representative operating level, as defined in § 98.98, and with the abatement systems connected to the stack system being tested operating with at least 90-percent uptime, averaged over all abatement systems, during the 8-hour (or longer) period for each stack system, or at no less than 90 percent of the abatement system uptime rate measured over the previous reporting year, averaged over all abatement systems. Hydrocarbon-fuel-based combustion emissions control systems that were purchased and installed on or after January 1, 2025, that are used to control emissions from tools that use either NF3 in remote plasma cleaning processes or F2 as an input gas in any process type or sub-type, and that are not certified not to form CF4, must operate with at least 90-percent uptime during the test. * * * * * (3) Fab-specific fluorinated GHG consumption measurements. You must determine the amount of each fluorinated GHG consumed by each fab during the sampling period for all process tools connected to the stack systems under § 98.93(i)(3), according to VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 the procedures in paragraphs (j)(3)(i) and (ii) of this section. * * * * * (5) Emissions testing frequency. You must conduct emissions testing to develop fab-specific emission factors on a frequency according to the procedures in paragraph (j)(5)(i) or (ii) of this section. (i) Annual testing. You must conduct an annual emissions test for each stack system unless you meet the criteria in paragraph (j)(5)(ii) of this section to skip annual testing. Each set of emissions testing for a stack system must be separated by a period of at least 2 months. (ii) Criteria to test less frequently. After the first 3 years of annual testing, you may calculate the relative standard deviation of the emission factors for each fluorinated GHG included in the test and use that analysis to determine the frequency of any future testing. As an alternative, you may conduct all three tests in less than 3 calendar years for purposes of this paragraph (j)(5)(ii), but this does not relieve you of the obligation to conduct subsequent annual testing if you do not meet the criteria to test less frequently. If the criteria specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met, you may use the arithmetic average of the three emission factors for each fluorinated GHG and fluorinated GHG byproduct for the current year and the next 4 years with no further testing unless your fab operations are changed in a way that triggers the re-test criteria in paragraph (j)(8) of this section. In the fifth year following the last stack test included in the previous average, you must test each of the stack systems and repeat the relative standard deviation analysis using the results of the most recent three tests (i.e. , the new test and the two previous tests conducted prior to the 4year period). If the criteria specified in paragraphs (j)(5)(ii)(A) and (B) of this section are not met, you must use the emission factors developed from the most recent testing and continue annual testing. You may conduct more than one test in the same year, but each set of emissions testing for a stack system must be separated by a period of at least 2 months. You may repeat the relative standard deviation analysis using the most recent three tests, including those tests conducted prior to the 4-year period, to determine if you are exempt from testing for the next 4 years. (A) The relative standard deviation of the total CO2e emission factors calculated from each of the three tests (expressed as the total CO2e fluorinated GHG emissions of the fab divided by the PO 00000 Frm 00115 Fmt 4701 Sfmt 4700 31915 total CO2e fluorinated GHG use of the fab) is less than or equal to 15 percent. (B) The relative standard deviation for all single fluorinated GHGs that individually accounted for 5 percent or more of CO2e emissions were less than 20 percent. * * * * * ■ 25. Amend § 98.96 by: ■ a. Revising paragraphs (c)(1) and (2); ■ b. Adding paragraph (o); and ■ c. Revising paragraphs (p)(2), (q)(2) and (3), (r)(2), (w)(2), (y) introductory text, (y)(1), (y)(2)(i) and (iv), and (y)(4). The revisions and addition read as follows: § 98.96 Data reporting requirements. * * * * * (c) * * * (1) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type for which your fab is required to calculate emissions as calculated in equations I– 6, I–7, and I–9 to § 98.93. (2) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type or process sub-type as calculated in equations I–8A and I–8B to § 98.93, as applicable. * * * * * (o) For all HC fuel CECS that were purchased and installed on or after January 1, 2025, that are used to control emissions from tools that use either NF3 as an input gas in remote plasma clean processes or F2 as an input gas in any process type or sub-type and for which you are not calculating emissions under equation I–9 to § 98.93, certification that the rate of conversion from F2 to CF4 is <0.1% and that the systems are installed, operated, and maintained in accordance with the directions of the HC fuel CECS manufacturer. Hydrocarbon-fuel-based combustion emissions control systems include but are not limited to abatement systems as defined in § 98.98 that are hydrocarbonfuel-based. If you make the certification based on your own testing, you must certify that you tested the model of the system according to the requirements specified in § 98.94(e). If you make the certification based on testing by the HC fuel CECS manufacturer, you must provide documentation from the HC fuel CECS manufacturer that the rate of conversion from F2 to CF4 is <0.1% when tested according to the requirements specified in § 98.94(e). (p) * * * (2) The basis of the destruction or removal efficiency being used (default, manufacturer-verified, or site-specific measurement according to E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations § 98.94(f)(4)(i)) for each process sub-type or process type and for each gas. (q) * * * (2) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), or (i), certification that the site maintenance plan for abatement systems for which emissions are being reported contains the manufacturer’s recommendations and specifications for installation, operation, and maintenance for each abatement system. To use the default or lower manufacturer-verified destruction or removal efficiency values, operation of the abatement system must be within manufacturer’s specifications, which may include, for example, specifications on vacuum pumps’ purges, fuel and oxidizer settings, supply and exhaust flows and pressures, and utilities to the emissions control equipment including fuel gas lotter on DSK11XQN23PROD with RULES2 SFGHG = ] [ L [ C1-cEF·f ct )) * cif * GWPi + Lk EFkf * L aif* if I Where: SFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO2e for which you calculated total emission according to the procedures in § 98.93(i)(3). EFif = Emission factor for fluorinated GHG input gas i, emitted from fab f, as calculated in equation I–19 to § 98.93 (kg emitted/kg input gas consumed). aif = Fraction of fluorinated GHG input gas i used in fab f in tools with abatement systems (expressed as a decimal fraction). dif = Fraction of fluorinated GHG i destroyed or removed in abatement systems connected to process tools in fab f, as calculated from equation I–24A to § 98.93, which you used to calculate total emissions according to the procedures in § 98.93(i)(3) (expressed as a decimal fraction). Cif = Total consumption of fluorinated GHG input gas i, of tools vented to stack systems, for fab f, for the reporting year, expressed in metric ton CO2e, which you used to calculate total emissions according to the procedures in § 98.93(i)(3) (expressed as a decimal fraction). EFkf = Emission factor for fluorinated GHG by-product gas k, emitted from fab f, as calculated in equation I–20 to § 98.93 (kg emitted/kg of all input gases consumed in tools vented to stack systems). akif = Fraction of fluorinated GHG by-product gas k emitted in fab f from tools using input gas i with abatement systems (expressed as a decimal fraction), as calculated using equation I–24D to § 98.93. VerDate Sep<11>2014 flow and pressure, calorific value, and water quality, flow and pressure. (3) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N2O abatement, as applicable. You must support this certification by providing abatement system supplier documentation stating that the system was designed for fluorinated GHG or N2O abatement, as applicable, and supply the destruction or removal efficiency value at which each abatement system is certified for the fluorinated GHG or N2O abated, as applicable. You may only use the default destruction or removal efficiency value if the abatement system is verified to meet or exceed the destruction or removal efficiency 19:27 Apr 24, 2024 Jkt 262001 c C·f I * * * * (w) * * * (2) An inventory of all stack systems from which process fluorinated GHG are emitted. * * * * * (y) If your semiconductor manufacturing facility manufactures wafers greater than 150 mm and emits more than 40,000 metric ton CO2e of GHG emissions, based on your most recently submitted annual report as required in paragraph (c) of this section, from the electronics manufacturing processes subject to reporting under this subpart, you must prepare and submit a technology assessment report every five years to the Administrator (or an authorized representative) that meets the requirements specified in paragraphs (y)(1) through (6) of this section. Any other semiconductor manufacturing facility may voluntarily submit this report to the Administrator. If your semiconductor manufacturing PO 00000 Frm 00116 Fmt 4701 Sfmt 4700 ct ) 1- akif" ik dik = Fraction of fluorinated GHG byproduct k destroyed or removed in abatement systems connected to process tools in fab f, as calculated from equation I–24B to § 98.93, which you used to calculate total emissions according to the procedures in § 98.93(i)(3) (expressed as a decimal fraction). GWPi = GWP of emitted fluorinated GHG i from table A–1 to subpart A of this part. GWPk = GWP of emitted fluorinated GHG byproduct k from table A–1 to subpart A of this part. i = Fluorinated GHG. k = Fluorinated GHG by-product. * default value in table I–16 to this subpart. If the system is verified at a destruction or removal efficiency value lower than the default value, you may use the verified value. * * * * * (r) * * * (2) Use equation I–28 to this section to calculate total unabated emissions, in metric ton CO2e, of all fluorinated GHG emitted from electronics manufacturing processes whose emissions of fluorinated GHG you calculated according to the stack testing procedures in § 98.93(i)(3). For each set of processes, use the same input gas consumption (Cif), input gas emission factors (EFif), by-product gas emission factors (EFkf), fractions of tools abated (aif and akif), and destruction efficiencies (dif and dik) to calculate unabated emissions as you used to calculate emissions. * GWPk] Eq. I-28 facility manufactures only 150 mm or smaller wafers, you are not required to prepare and submit a technology assessment report, but you are required to prepare and submit a report if your facility begins manufacturing wafers 200 mm or larger during or before the calendar year preceding the year the technology assessment report is due. If your semiconductor manufacturing facility is no longer required to report to the GHGRP under subpart I due to the cessation of semiconductor manufacturing as described in § 98.2(i)(3), you are not required to submit a technology assessment report. (1) The first technology assessment report due after January 1, 2025, is due on March 31, 2028, and subsequent reports must be delivered every 5 years no later than March 31 of the year in which it is due. (2) * * * (i) It must describe how the gases and technologies used in semiconductor manufacturing using 200 mm and 300 mm wafers in the United States have changed in the past 5 years and whether any of the identified changes are likely to have affected the emissions characteristics of semiconductor manufacturing processes in such a way that the default utilization and byproduct formation rates or default destruction or removal efficiency factors of this subpart may need to be updated. * * * * * E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.033</GPH> 31916 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (iv) It must provide any utilization and byproduct formation rates and/or destruction or removal efficiency data that have been collected in the previous 5 years that support the changes in semiconductor manufacturing processes described in the report. Any utilization or byproduct formation rate data submitted must be reported using both of the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this section if multiple fluorinated input gases are used, unless one of the input gases does not have a reference process utilization rate in table I–19 or I–20 to this subpart for the process type and wafer size whose emission factors are being measured, in which case the data must be submitted using the method specified in paragraph (y)(2)(iv)(A) of this section. If only one fluorinated input gas is fed into the process, you must use equations I–29A and I–29B to this section. In addition to using the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this section, you have the option to calculate and report the utilization or byproduct formation rate data using any alternative calculation methodology. The report must include the input gases used and measured, the utilization rates measured, the byproduct formation rates measured, the process type, the process subtype for chamber clean processes, the wafer size, and the methods used for the measurements. The report must also specify the method used to calculate each reported utilization and by-product formation rate, and provide a unique record number for each data set. For any destruction or removal efficiency data submitted, the report must include the input gases used and measured, the destruction and removal efficiency measured, the process type, the methods used for the measurements, and whether the abatement system is specifically designed to abate the gas measured under the operating conditions used for the measurement. If you choose to use an additional alternative calculation methodology to calculate and report the input gas emission factors and byproduct formation rates, you must provide a complete, mathematical description of the alternative method used (including the equation used to calculate each reported utilization and by-product formation rate) and include the information in this paragraph (y)(2)(iv). 31917 (A) All-input gas method. Use equation I–29A to this section to calculate the input gas emission factor (1 ¥ Uij) for each input gas in a single test. If the result of equation I–29A exceeds 0.8 for an F–GHG that contains carbon, you must use equation I–29C to this section to calculate the input gas emission factor for that F–GHG and equation I–29D to this section to calculate the by-product formation rate for that F–GHG from the other input gases. Use equation I–29B to this section to calculate the by-product formation rates from each input gas for F–GHGs that are not input gases. If a test uses a cleaning or etching gas that does not contain carbon in combination with a cleaning or etching gas that does contain carbon and the process chamber is not used to etch or deposit carboncontaining films, you may elect to assign carbon containing by-products only to the carbon-containing input gases. If you choose to assign carbon containing by-products only to carboncontaining input gases, remove the input mass of the non-carbon containing gases from the sum of Massi and the sum of Massg in equations I–29B and I–29D to this section, respectively. (Eq. I-29A) Where: Uij = Process utilization rate for fluorinated GHG i, process type j. Ei = The mass emissions of input gas i. Massi = The mass of input gas i fed into the process. i = Fluorinated GHG. j = Process type. (Eq. I-29B) Where: BEFkji = By-product formation rate for gas k from input gas i, for process type j, where gas k is not an input gas. Ek = The mass emissions of by-product gas k. Massi = The mass of input gas i fed into the process. i = Fluorinated GHG. j = Process type. k = Fluorinated GHG by-product. Where: BEFijg = By-product formation rate for gas i from input gas g for process type j. Ei = The mass emissions of input gas i. Massi = The mass of input gas i fed into the process. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 Massg = The mass of input gas g fed into the process, where g does not equal input gas i. i = Fluorinated GHG. g = Fluorinated GHG input gas, where gas g is not equal to gas i. j = Process type. PO 00000 Frm 00117 Fmt 4701 Sfmt 4700 (B) Reference emission factor method. Calculate the input gas emission factors and by-product formation rates from a test using equations I–30A, I–30B, and I–29B to this section, and table I–19 or I–20 to this subpart. In this case, use E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.036</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. I-29D) ER25AP24.035</GPH> Uij = Process utilization rate for fluorinated GHG i, process type j. ER25AP24.034</GPH> Where: ER25AP24.037</GPH> (Eq. I-29C) 31918 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations u..11) 1- u..IJr ) * = (1- Where: Uij = Process utilization rate for fluorinated GHG i, process type j. Uijr = Reference process utilization rate for fluorinated GHG i, process type j, for input gas i, using table I–19 or I–20 to this subpart as appropriate. BEf.. = BEf.. IJg IJgr lotter on DSK11XQN23PROD with RULES2 * * * * (4) Multiple semiconductor manufacturing facilities may submit a single consolidated technology assessment report as long as the facility identifying information in § 98.3(c)(1) and the certification statement in § 98.3(c)(9) is provided for each facility for which the consolidated report is submitted. * * * * * ■ 26. Amend § 98.97 by: ■ a. Adding paragraph (b); ■ b. Revising paragraphs (d)(1)(iii), (d)(3), (d)(5)(i), (d)(6) and (7), and (d)(9)(i); ■ c. Removing and reserving paragraph (i)(1); and ■ d. Revising paragraphs (i)(5) and (9) and (k). The addition and revisions read as follows: § 98.97 * * Records that must be retained. * VerDate Sep<11>2014 * * 19:27 Apr 24, 2024 Jkt 262001 E·I ] (Massi* (1- Uijr)+Lg MassgBEFijgr) Ei = The mass emissions of input gas i. Massi = The mass of gas i fed into the process. Massg = The mass of input gas g fed into the process, where g does not equal input gas i. BEFijgr = Reference by-product formation rate for gas i from input gas g for process type * Where: BEFijg = By-product formation rate for gas i from input gas g for process type j, where gas i is also an input gas. BEFijgr = Reference by-product formation rate for gas i from input gas g for process type j from table I–19 or I–20 to this subpart, as appropriate. Uijr = Reference process utilization rate for fluorinated GHG i, process type j, for input gas i, using table I–19 or I–20 to this subpart, as appropriate. Ei = The mass emissions of input gas i. Massi = The mass of gas i fed into the process. Massg = The mass of input gas g fed into the process, where g does not equal input gas i. i = Fluorinated GHG. j = Process type. g = Fluorinated GHG input gas, where gas g is not equal to gas i. r = Reference data. * [ [ (Eq. I-30A) j, using table I–19 or I–20 to this subpart as appropriate. i = Fluorinated GHG. g = Fluorinated GHG input gas, where gas g is not equal to gas i. r = Reference data. E·I ] (Mass* (1-Uijr)+ LgMassg BEFijgr) (b) If you use HC fuel CECS purchased and installed on or after January 1, 2025, to control emissions from tools that use either NF3 as an input gas in remote plasma cleaning processes or F2 as an input gas in any process, and if you use a value less than 1 for either aF2,j or aNF3,RPC in equation I–9 to § 98.93, certification and documentation that the model for each of the systems that you claim does not form CF4 from F2 has been tested and verified to produce less than 0.1% CF4 from F2, and certification that the site maintenance plan includes the HC fuel CECS manufacturer’s recommendations and specifications for installation, operation, and maintenance of those systems. If you are relying on your own testing to make the certification that the model produces less than 0.1% CF4 from F2, the documentation must include the model tested, the method used to perform the testing (e.g., EPA 430–R–10–003, modified to calculate the formation rate of CF4 from F2 rather than the DRE), complete documentation of the results of any initial and subsequent tests, and a final report similar to that specified in EPA 430–R–10–003 (incorporated by reference, see § 98.7), with appropriate adjustments to reflect the measurement of the formation rate of CF4 from F2 rather than the DRE. If you are relying on testing by the HC fuel CECS manufacturer to make the certification that the system produces less than 0.1% CF4 from F2, the documentation must include the model tested, the method used to perform the testing, and the results of the test. * * * * * (d) * * * (1) * * * (iii) If you use either default destruction or removal efficiency values PO 00000 Frm 00118 Fmt 4701 Sfmt 4700 (Eq. I-30B) or certified destruction or removal efficiency values that are lower than the default values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG and N2O abatement, as required under § 98.94(f)(3), certification that the site maintenance plan includes the abatement system manufacturer’s recommendations and specifications for installation, operation, and maintenance, and the certified destruction and removal efficiency values for all applicable abatement systems. For abatement systems purchased and installed on or after January 1, 2025, also include records of the method used to measure the destruction and removal efficiency values. * * * * * (3) Where either the default destruction or removal efficiency value or a certified destruction or removal efficiency value that is lower than the default is used, documentation from the abatement system supplier describing the equipment’s designed purpose and emission control capabilities for fluorinated GHG and N2O. * * * * * (5) * * * (i) The number of abatement systems of each manufacturer, and model numbers, and the manufacturer’s certified fluorinated GHG and N2O destruction or removal efficiency, if any. * * * * * (6) Records of all inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, in accordance with equations I–15 or I–23 to § 98.93, as applicable. The inputs should E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.039</GPH> ( this section to calculate the by-product formation rates. ER25AP24.038</GPH> equation I–30A to this section to calculate the input gas emission factors and use equation I–30B and I–29B to 31919 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations include an indication of whether each value for destruction or removal efficiency is a default value, lower manufacturer-verified value, or a measured site-specific value. (7) Records of all inputs and results of calculations made to determine the average weighted fraction of each gas destroyed or removed in the abatement systems for each stack system using equations I–24A and I–24B to § 98.93, if applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value, lower manufacturerverified value, or a measured sitespecific value. * * * * * (9) * * * (i) The site maintenance plan for abatement systems must be based on the abatement system manufacturer’s recommendations and specifications for installation, operation, and maintenance if you use default or lower manufacturer-verified destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If the manufacturer’s recommendations and specifications for installation, operation, and maintenance are not available, you cannot use default destruction and removal efficiency values or lower manufacturer-verified value in your emissions calculations under § 98.93(a), (b), and/or (i). If you use an average of properly measured destruction or removal efficiencies determined in accordance with the procedures in § 98.94(f)(4)(i) through (vi), the site maintenance plan for abatement systems must be based on the abatement system manufacturer’s recommendations and specifications for installation, operation, and maintenance, where available. If you deviate from the manufacturer’s recommendations and specifications, you must include documentation that demonstrates how the deviations do not negatively affect the performance or destruction or removal efficiency of the abatement systems. * * * * * (i) * * * (5) The fab-specific emission factor and the calculations and data used to determine the fab-specific emission factor for each fluorinated GHG and byproduct, as calculated using equations I–19A, I–19B, I–19C and I–20 to § 98.93(i)(3). * * * * * (9) The number of tools vented to each stack system in the fab and all inputs and results for the calculations accounting for the fraction of gas exhausted through abatement systems using equations I–24C and I–24D to § 98.93. * * * * * (k) Annual gas consumption for each fluorinated GHG and N2O as calculated in equation I–11 to § 98.93, including where your fab used less than 50 kg of a particular fluorinated GHG or N2O used at your facility for which you have not calculated emissions using equations I–6, I–7, I–8A, I–8B, I–9, I–10, I–21, or I–22 to § 98.93, the chemical name of the GHG used, the annual consumption of the gas, and a brief description of its use. * * * * * ■ 27. Amend § 98.98 by: ■ a. Removing the definition ‘‘Fluorinated heat transfer fluids’’; ■ b. Adding the definition ‘‘Hydrocarbon-fuel based combustion emission control systems (HC fuel CECs)’’ in alphabetical order; and ■ c. Revising the definition ‘‘Operational mode’’. The revisions and addition read as follows: § 98.98 Definitions. * * * * * Hydrocarbon-fuel based combustion emission control system (HC fuel CECS) means a hydrocarbon fuel-based combustion device or equipment that is designed to destroy or remove gas emissions in exhaust streams via combustion from one or more electronics manufacturing production processes, and that is connected to manufacturing tools that have the potential to emit F2 or fluorinated greenhouse gases. HC fuel CECs include both emission control systems that are and are not designed to destroy or remove fluorinated GHGs or N2O. * * * * * Operational mode means the time in which an abatement system is properly installed, maintained, and operated according to the site maintenance plan for abatement systems as required in § 98.94(f)(1) and defined in § 98.97(d)(9). This includes being properly operated within the range of parameters as specified in the site maintenance plan for abatement systems. For abatement systems purchased and installed on or after January 1, 2025, this includes being properly operated within the range of parameters specified in the DRE certification documentation. An abatement system is considered to not be in operational mode when it is not operated and maintained according to the site maintenance plan for abatement systems or, for abatement systems purchased and installed on or after January 1, 2025, not operated within the range of parameters as specified in the DRE certification documentation. * * * * * 28. Revise table I–1 to subpart I to read as follows: ■ TABLE I–1 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS FOR MANUFACTURING CAPACITY-BASED THRESHOLD APPLICABILITY DETERMINATION Emission factors EFi Product type CF4 Semiconductors (kg/m2) ................................... LCD (g/m2) ....................................................... MEMS (kg/m2) ................................................. 0.9 0.65 0.015 C2F6 1.0 NA NA CHF3 0.04 0.0024 NA c-C4F8 C3F8 NA 0.00 0.076 0.05 NA NA lotter on DSK11XQN23PROD with RULES2 Notes: NA denotes not applicable based on currently available information. 29. Revise table I–2 to subpart I to read as follows: ■ VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00119 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 NF3 0.04 1.29 NA SF6 0.20 4.14 1.86 N 2O NA 17.06 NA 31920 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE I–2 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS FOR GAS CONSUMPTION-BASED THRESHOLD APPLICABILITY DETERMINATION Process gas i Fluorinated GHGs 1–Ui .......................................................................................................................................................... BCF4 ........................................................................................................................................................ BC2F6 ....................................................................................................................................................... N2O 0.8 0.15 0.05 1 0 0 30. Revise table I–3 to subpart I to read as follows: ■ TABLE I–3 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 150 mm AND 200 mm WAFER SIZES Process gas i Process type/sub-type C2F6 CF4 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 0.19 0.0040 0.025 NA NA NA 0.55 0.13 0.11 NA NA 0.0012 C4F6 C 5F 8 C 4F 8O 0.083 0.095 0.073 NA NA 0.066 0.072 NA 0.014 NA NA 0.0039 NA NA NA NA NA NA NA NA NA NA 0.14 0.13 0.045 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA Etching/Wafer Cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC4F8 ........................................ BC3F8 ........................................ BCHF3 ....................................... I 0.73 NA 0.041 NA NA 0.091 I 0.72 0.10 NA NA NA 0.047 I 0.51 0.085 0.035 NA NA NA I 0.13 0.079 0.025 NA NA 0.049 I 0.064 0.077 0.024 NA NA NA I 0.70 NA 0.0034 NA NA NA NA NA NA NA NA NA I I 0.14 0.11 0.037 NA NA 0.040 I I I I Chamber Cleaning In situ plasma cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ I 0.92 NA NA NA 0.55 0.19 NA NA I I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA 0.40 0.20 NA NA I I 0.10 0.11 NA NA 0.18 0.14 NA NA I I NA NA NA NA I NA NA NA NA I Remote plasma cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ BF2 ............................................ I NA NA NA NA NA NA NA NA NA NA I I NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA I NA NA NA NA NA I NA NA NA NA NA I 0.028 0.015 NA NA 0.5 I NA NA NA NA NA I In situ thermal cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ I NA NA NA NA NA NA NA NA I I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I I Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type. 31. Revise table I–4 to subpart I to read as follows: TABLE I–4 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 300 mm AND 450 mm WAFER SIZE Process gas i Process type/sub-type CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 0.30 0.033 0.041 NA NA 0.0039 0.000020 0.0082 0.15 0.059 0.062 0.0051 NA 0.017 0.000030 0.00065 C5F8 C4F8O lotter on DSK11XQN23PROD with RULES2 Etching/Wafer Cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC4F8 ........................................ BC3F8 ........................................ BCHF3 ....................................... BCH2F2 ..................................... BCH3F ....................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 0.65 NA 0.058 0.0046 NA 0.012 0.005 0.0061 Jkt 262001 0.80 0.21 NA NA NA NA NA NA 0.37 0.076 0.058 0.0027 NA NA 0.0024 0.027 PO 00000 0.20 0.060 0.043 0.054 NA 0.057 NA 0.0036 Frm 00120 0.30 0.0291 0.009 0.0070 NA 0.016 0.0033 NA 0.30 0.21 0.018 NA NA 0.012 NA 0.00073 Fmt 4701 Sfmt 4700 0.18 0.045 0.027 NA NA 0.028 0.0021 0.0063 0.16 0.044 0.045 NA NA 0.023 0.00074 0.0080 E:\FR\FM\25APR2.SGM 25APR2 0.10 0.11 0.083 NA 0.00012 0.0069 NA NA NA NA NA NA NA NA NA NA 31921 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE I–4 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 300 mm AND 450 mm WAFER SIZE—Continued Process gas i Process type/sub-type CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O Chamber Cleaning In situ plasma cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ NA NA NA NA I NA NA NA NA I I NA NA NA NA NA NA NA NA I NA NA NA NA NA NA NA NA NA NA NA NA 0.20 0.037 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.018 0.037 NA NA 0.000059 0.00088 0.0028 0.5 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.28 0.010 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA Remote plasma cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ BCHF3 ....................................... BCH2F2 ..................................... BCH3F ....................................... BF2 ............................................ NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.063 NA NA NA NA NA NA NA In situ thermal cleaning 1–Ui ........................................... BCF4 .......................................... BC2F6 ........................................ BC3F8 ........................................ NA NA NA NA I NA NA NA NA I I NA NA NA NA NA NA NA NA I NA NA NA NA NA NA NA NA I Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type. 32. Revise table I–8 to subpart I to read as follows: ■ TABLE I–8 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–UN2O,j) FOR N2O UTILIZATION (UN2O,j) Manufacturing type/process type/wafer size N2O Semiconductor Manufacturing: 200 mm or Less: CVD 1–Ui ............................................................................................................................................................................... Other Manufacturing Process 1–Ui ....................................................................................................................................... 300 mm or greater: CVD 1–Ui ............................................................................................................................................................................... Other Manufacturing Process 1–Ui ....................................................................................................................................... LCD Manufacturing: CVD Thin Film Manufacturing 1–Ui .............................................................................................................................................. All other N2O Processes ..................................................................................................................................................................... 1.0 1.0 0.5 1.0 0.63 1.0 33. Revise table I–11 to subpart I to read as follows: ■ TABLE I–11 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR USE WITH THE STACK TEST METHOD [150 mm and 200 mm Wafers] Process gas i lotter on DSK11XQN23PROD with RULES2 All processes 1–Ui .................... BCF4 ................... BC2F6 ................. BC4F8 ................. BC3F8 ................. BC5F8 ................. BCHF3 ................ BF2 ..................... CF4 C2F6 CHF3 0.79 NA 0.027 NA NA 0.00077 0.060 NA 0.55 0.19 NA NA NA NA 0.0020 NA 0.51 0.085 0.035 NA NA 0.0012 NA NA CH2F2 C2HF5 0.13 0.079 0.025 NA NA NA 0.049 NA 0.064 0.077 0.024 NA NA NA NA NA CH3F 0.70 NA 0.0034 NA NA NA NA NA C3F8 0.40 0.20 NA NA NA NA NA NA C4F8 NF3 0.12 0.11 0.019 NA NA 0.0043 0.020 NA 0.18 0.11 0.0059 NA NA NA NA NA NF3 Remote 0.028 0.015 NA NA NA NA NA 0.50 SF6 C4F6 C5F8 0.58 0.13 0.10 NA NA NA 0.0011 NA 0.083 0.095 0.073 NA NA NA 0.066 NA 0.072 NA 0.014 NA NA NA 0.0039 NA C4F8O 0.14 0.13 0.045 NA NA NA NA NA Notes: NA = Not applicable; i.e., there are no applicable emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00121 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31922 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 34. Revise table I–12 to subpart I to read as follows: ■ TABLE I–12 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR USE WITH THE STACK TEST METHOD [300 mm and 450 mm Wafers] Process gas i All processes 1–Ui .................. BCF4 ................. BC2F6 ............... BC4F6 ............... BC4F8 ............... BC3F8 ............... BCH2F2 ............. BCH3F .............. BCHF3 .............. BF2 ................... CF4 C2F6 CHF3 CH2F2 CH3F C3F8 0.65 NA 0.058 0.0083 0.0046 NA 0.005 0.0061 0.012 NA 0.80 0.21 NA NA NA NA NA NA NA NA 0.37 0.076 0.058 0.01219 0.00272 NA 0.0024 0.027 NA NA 0.20 0.060 0.043 NA 0.054 NA NA 0.0036 0.057 NA 0.30 0.029 0.0093 0.001 0.007 NA 0.0033 NA 0.016 NA 0.30 0.21 0.18 NA NA NA NA 0.0007 0.012 NA C3F8 Remote 0.063 NA NA NA NA NA NA NA NA NA C4F8 NF3 NF3 Remote SF6 C4F6 0.183 0.045 0.027 0.008 NA NA 0.0021 0.0063 0.028 NA 0.19 0.040 0.0204 NA NA NA 0.00034 0.0036 0.0106 NA 0.018 0.037 NA NA NA NA 0.00088 0.0028 0.000059 0.50 0.30 0.033 0.041 NA NA NA 0.000020 0.0082 0.0039 NA 0.15 0.059 0.062 NA 0.0051 NA 0.000030 0.00065 0.017 NA C5F8 C 4 F8 O 0.100 0.109 0.083 NA NA 0.00012 NA NA 0.0069 NA NA NA NA NA NA NA NA NA NA NA 35. Revise table I–16 to subpart I to read as follows: ■ TABLE I–16 TO SUBPART I OF PART 98—DEFAULT EMISSION DESTRUCTION OR REMOVAL EFFICIENCY (DRE) FACTORS FOR ELECTRONICS MANUFACTURING Default DRE (%) Manufacturing type/process type/gas MEMS, LCDs, and PV Manufacturing ................................................................................................................................................. Semiconductor Manufacturing: CF4 ............................................................................................................................................................................................... CH3F ............................................................................................................................................................................................. CHF3 ............................................................................................................................................................................................. CH2F2 ........................................................................................................................................................................................... C4F8 .............................................................................................................................................................................................. C4F8O ........................................................................................................................................................................................... C5F8 .............................................................................................................................................................................................. C4F6 .............................................................................................................................................................................................. C3F8 .............................................................................................................................................................................................. C2HF5 ........................................................................................................................................................................................... C2F6 .............................................................................................................................................................................................. SF6 ................................................................................................................................................................................................ NF3 ............................................................................................................................................................................................... All other carbon-based fluorinated GHGs used in Semiconductor Manufacturing ............................................................................. N2O Processes. CVD and all other N2O-using processes ............................................................................................................................................ 60 87 98 97 98 93 93 97 95 98 97 98 95 96 60 60 36. Add table I–18 to subpart I to read as follows: ■ TABLE I–18 TO SUBPART I OF PART 98—DEFAULT FACTORS FOR GAMMA (gi,p AND gk,i,p) FOR SEMICONDUCTOR MANUFACTURING AND FOR MEMS AND PV MANUFACTURING UNDER CERTAIN CONDITIONS * FOR USE WITH THE STACK TESTING METHOD Process type In-situ thermal or in-situ plasma cleaning Gas CF4 C2F6 c-C4F8 NF3 Remote plasma cleaning SF6 C3F8 CF4 NF3 lotter on DSK11XQN23PROD with RULES2 If manufacturing wafer sizes ≤200 mm AND manufacturing 300 mm (or greater) wafer sizes gi ........................................................................................................ gCF4,i .................................................................................................. gC2F6,i ................................................................................................. gCHF3,i ................................................................................................ gCH2F2,i ............................................................................................... gCH3F,i ................................................................................................ I 13 NA NA NA NA NA I 9.3 23 NA NA NA NA 4.7 6.7 NA NA NA NA 14 63 NA NA NA NA 11 8.7 3.4 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 11 NA NA If manufacturing ≤200 mm OR manufacturing 300 mm (or greater) wafer sizes gi (≤ 200 mm wafer size) ................................................................... VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00122 13 Fmt 4701 9.3 Sfmt 4700 4.7 2.9 E:\FR\FM\25APR2.SGM 25APR2 I 5.7 58 NA 0.24 111 33 1.4 31923 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE I–18 TO SUBPART I OF PART 98—DEFAULT FACTORS FOR GAMMA (gi,p AND gk,i,p) FOR SEMICONDUCTOR MANUFACTURING AND FOR MEMS AND PV MANUFACTURING UNDER CERTAIN CONDITIONS * FOR USE WITH THE STACK TESTING METHOD—Continued Process type In-situ thermal or in-situ plasma cleaning Gas CF4 gCF4,i (≤200 mm wafer size) .............................................................. gC2F6,i (≤200 mm wafer size) ............................................................ gi (300 mm wafer size) ...................................................................... gCF4,i (300 mm wafer size) ................................................................ gC2F6,i (300 mm wafer size) .............................................................. gCHF3,i (300 mm wafer size) .............................................................. gCH2F2,i (300 mm wafer size) ............................................................ gCH3F,i (300 mm wafer size) .............................................................. C2F6 NA NA NA NA NA NA NA NA c-C4F8 23 NA NA NA NA NA NA NA NF3 6.7 NA NA NA NA NA NA NA Remote plasma cleaning SF6 110 NA 26 17 NA NA NA NA C3F8 8.7 3.4 NA NA NA NA NA NA CF4 NA NA NA NA NA NA NA NA NF3 NA NA NA NA NA NA NA NA 36 NA 10 80 NA 0.24 111 33 * If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use the corresponding g in this table. For all other tools and processes, a default g of 10 must be used. ■ 37. Add table I–19 to subpart I to read as follows: TABLE I–19 TO SUBPART I OF PART 98—REFERENCE EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BY-PRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 150 MM AND 200 MM WAFER SIZES Process gas i Process type/sub-type C2F6 CF4 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O Etching/Wafer Cleaning 1–Ui ................................................... BCF4 .................................................. BC2F6 ................................................ BC4F6 ................................................ BC4F8 ................................................ BC3F8 ................................................ BC5F8 ................................................ BCHF3 ............................................... 0.73 NA 0.029 NA NA NA NA 0.13 0.46 0.20 NA NA NA NA NA NA 0.31 0.10 NA NA NA NA NA NA 0.37 0.031 NA NA NA NA NA NA 0.064 0.077 NA NA NA NA NA NA 0.66 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.21 0.17 0.065 NA NA NA 0.016 NA 0.20 0.0040 NA NA NA NA NA NA 0.55 0.023 NA NA NA NA NA NA 0.086 0.0089 0.045 NA NA NA NA NA 0.072 NA 0.014 NA NA NA NA 0.0039 NA NA NA NA NA NA NA NA 0.40 0.20 NA NA 0.10 0.11 NA NA 0.18 0.14 NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.14 0.13 0.045 NA Chamber Cleaning In situ plasma cleaning 1–Ui ................................................... BCF4 .................................................. BC2F6 ................................................ BC3F8 ................................................ I 0.92 NA NA NA I 0.55 0.19 NA NA I NA NA NA NA NA NA NA NA I I NA NA NA NA I NA NA NA NA I I I I I I I Remote plasma cleaning 1–Ui ................................................... BCF4 .................................................. BC2F6 ................................................ BC3F8 ................................................ I NA NA NA NA I NA NA NA NA I NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA I NA NA NA NA I NA NA NA NA I 0.028 0.015 NA NA I NA NA NA NA I NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA In situ thermal cleaning 1–Ui ................................................... BCF4 .................................................. BC2F6 ................................................ BC3F8 ................................................ I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I NA NA NA NA I 38. Add table I–20 to subpart I to read as follows: lotter on DSK11XQN23PROD with RULES2 ■ VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00123 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 NA NA NA NA I I I VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00124 Fmt 4701 NA NA NA NA NA NA NA NA NA NA NA 1–Ui ............................................................................................... BCF4 ............................................................................................. BC2F6 ............................................................................................ BC3F8 ............................................................................................ NA NA NA NA 0.68 NA 0.041 0.0015 0.0051 NA NA 0.0056 0.014 0.00057 CF4 1–Ui ............................................................................................... BCF4 ............................................................................................. BC2F6 ............................................................................................ BC3F8 ............................................................................................ BCHF3 ........................................................................................... BCH2F2 ......................................................................................... BCH3F ........................................................................................... 1–Ui ............................................................................................... BCF4 ............................................................................................. BC2F6 ............................................................................................ BC3F8 ............................................................................................ 1–Ui ............................................................................................... BCF4 ............................................................................................. BC2F6 ............................................................................................ BC4F6 ............................................................................................ BC4F8 ............................................................................................ BC3F8 ............................................................................................ BC5F8 ............................................................................................ BCHF3 ........................................................................................... BCH2F2 ......................................................................................... BCH3F ........................................................................................... Process type/sub-type Sfmt 4700 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.80 0.21 NA NA NA NA NA NA NA NA C2F6 CH2F2 CH3F 0.15 0.020 0.0065 NA NA NA NA 0.033 NA NA 0.34 0.038 0.0064 0.0010 0.0070 NA NA 0.0049 0.0023 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA In situ thermal cleaning NA NA NA NA NA NA NA Remote plasma cleaning NA NA NA NA In situ plasma cleaning Chamber Cleaning 0.35 0.073 0.040 0.00010 0.00061 NA NA NA 0.0026 0.12 Etching/Wafer Cleaning CHF3 NA NA NA NA 0.063 NA NA NA NA NA NA NA NA NA NA 0.30 0.21 0.18 NA NA NA NA 0.012 NA 0.00073 C 3F 8 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.16 0.045 0.030 0.00083 NA NA NA 0.029 0.0014 NA C4F8 Process gas i 0.28 0.010 NA NA 0.018 0.038 NA NA 0.000059 0.0016 0.0028 0.20 0.037 NA NA 0.17 0.035 0.038 NA NA NA NA 0.0065 0.00086 NA NF3 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.28 0.0072 0.0017 NA NA NA NA 0.0012 0.000020 0.0082 SF6 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.17 0.034 0.025 NA NA NA NA 0.019 0.000030 NA C 4F 6 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA 0.10 0.11 0.083 NA NA 0.00012 NA 0.0069 NA NA C 5F 8 NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA NA C4F8O TABLE I–20 TO SUBPART I OF PART 98—REFERENCE EMISSION FACTORS (1–Uij) FOR GAS UTILIZATION RATES (Uij) AND BY-PRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 300 MM WAFER SIZES lotter on DSK11XQN23PROD with RULES2 31924 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations 31925 39. Add table I–21 to subpart I to read as follows: ■ TABLE I–21 TO SUBPART I OF PART 98—EXAMPLES OF FLUORINATED GHGS USED BY THE ELECTRONICS INDUSTRY Product type Fluorinated GHGs used during manufacture Electronics ....................................... CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, CHF3, CH2F2, NF3, SF6, and fluorinated HTFs (CF3-(OCF(CF3)-CF2)n-(O-CF2)m-O-CF3, CnF2n+2, CnF2n+1(O)CmF2m+1, CnF2nO, (CnF2n+1)3N). Subpart N—Glass Production 40. Revise and republish § 98.146 to read as follows: ■ lotter on DSK11XQN23PROD with RULES2 § 98.146 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable. (a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required under § 98.36 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) through (3) of this section: (1) Annual quantity of each carbonatebased raw material (tons) charged to each continuous glass melting furnace and for all furnaces combined. (2) Annual quantity of glass produced (tons), by glass type, from each continuous glass melting furnace and from all furnaces combined. (3) Annual quantity (tons), by glass type, of recycled scrap glass (cullet) charged to each continuous glass melting furnace and for all furnaces combined. (b) If a CEMS is not used to determine CO2 emissions from continuous glass melting furnaces, and process CO2 emissions are calculated according to the procedures specified in § 98.143(b), then you must report the following information as specified in paragraphs (b)(1) through (9) of this section: (1) Annual process emissions of CO2 (metric tons) for each continuous glass melting furnace and for all furnaces combined. (2) Annual quantity of each carbonatebased raw material charged (tons) to all furnaces combined. (3) Annual quantity of glass produced (tons), by glass type, from each continuous glass melting furnace and from all furnaces combined. (4) Annual quantity (tons), by glass type, of recycled scrap glass (cullet) charged to each continuous glass melting furnace and for all furnaces combined. (5) Results of all tests, if applicable, used to verify the carbonate-based VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (iii) of this section. (i) Date of test. (ii) Method(s) and any variations used in the analyses. (iii) Mass fraction of each sample analyzed. (6) [Reserved] (7) Method used to determine decimal fraction of calcination, unless you used the default value of 1.0. (8) Total number of continuous glass melting furnaces. (9) The number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials, recycled scrap glass (cullet), or mass fraction of the carbonate-based minerals for any continuous glass melting furnace (months). ■ 41. Amend § 98.147 by revising and republishing paragraphs (a) and (b) to read as follows: § 98.147 Records that must be retained. * * * * * (a) If a CEMS is used to measure emissions, then you must retain the records required under § 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) through (3) of this section: (1) Monthly glass production rate for each continuous glass melting furnace, by glass type (tons). (2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons). (3) Monthly amount (tons) of recycled scrap glass (cullet) charged to each continuous glass melting furnace, by glass type. (b) If process CO2 emissions are calculated according to the procedures specified in § 98.143(b), you must retain the records in paragraphs (b)(1) through (6) of this section. (1) Monthly glass production rate for each continuous glass melting furnace, by glass type (tons). (2) Monthly amount of each carbonate-based raw material charged to PO 00000 Frm 00125 Fmt 4701 Sfmt 4700 each continuous glass melting furnace (tons). (3) Monthly amount (tons) of recycled scrap glass (cullet) charged to each continuous glass melting furnace, by glass type. (4) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in equation N–1 to § 98.143, if applicable. (5) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(5)(i) through (v) of this section. (i) Date of test. (ii) Method(s), and any variations of the methods, used in the analyses. (iii) Mass fraction of each sample analyzed. (iv) Relevant calibration data for the instrument(s) used in the analyses. (v) Name and address of laboratory that conducted the tests. (6) The decimal fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO2. * * * * * Subpart P—Hydrogen Production ■ 42. Revise § 98.160 to read as follows: § 98.160 Definition of the source category. (a) A hydrogen production source category consists of facilities that produce hydrogen gas as a product. (b) This source category comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of feedstocks except the processes listed in paragraph (b)(1) or (2) of this section. (1) Any process unit for which emissions are reported under another subpart of this part. This includes, but is not necessarily limited to: (i) Ammonia production units for which emissions are reported under subpart G. (ii) Catalytic reforming units at petroleum refineries that transform E:\FR\FM\25APR2.SGM 25APR2 31926 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations naphtha into higher octane aromatics for which emissions are reported under subpart Y. (iii) Petrochemical process units for which emissions are reported under subpart X. (2) Any process unit that only separates out diatomic hydrogen from a gaseous mixture and is not associated with a unit that produces hydrogen created by transformation of one or more feedstocks, other than those listed in paragraph (b)(1) of this section. (c) This source category includes the process units that produce hydrogen and stationary combustion units directly associated with hydrogen production (e.g. , reforming furnace and hydrogen production process unit heater). ■ 43. Amend § 98.162 by revising paragraph (a) to read as follows: § 98.162 GHGs to report. * * * * * (a) CO2 emissions from each hydrogen production process unit, including fuel combustion emissions accounted for in the calculation methodologies in § 98.163. * * * * * ■ 44. Amend § 98.163 by revising the introductory text, paragraph (b) introductory text, and paragraph (c) to read as follows: lotter on DSK11XQN23PROD with RULES2 § 98.163 Calculating GHG emissions. You must calculate and report the annual CO2 emissions from each hydrogen production process unit using the procedures specified in paragraphs (a) through (c) of this section, as applicable. * * * * * (b) Fuel and feedstock material balance approach. Calculate and report CO2 emissions as the sum of the annual emissions associated with each fuel and feedstock used for each hydrogen production process unit by following paragraphs (b)(1) through (3) of this section. The carbon content and molecular weight shall be obtained from the analyses conducted in accordance with § 98.164(b)(2), (3), or (4), as applicable, or from the missing data procedures in § 98.165. If the analyses are performed annually, then the annual value shall be used as the monthly average. If the analyses are performed more frequently than monthly, use the arithmetic average of values obtained during the month as the monthly average. * * * * * (c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 that reports CO2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, then the owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. If GHG emissions from a hydrogen production process unit using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part does not include combustion emissions from the hydrogen production unit (i.e. , the hydrogen production unit has separate stacks for process and combustion emissions), then the calculation methodology in paragraph (b) of this section shall be used considering only fuel inputs to calculate and report CO2 emissions from fuel combustion related to the hydrogen production unit. ■ 45. Amend § 98.164 by: ■ a. Revising the introductory text, paragraphs (b)(2) through (4), and (b)(5) introductory text; and ■ b. Adding paragraphs (b)(5)(xix) and (c). The revisions and additions read as follows: § 98.164 Monitoring and QA/QC requirements. The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraph (a) or (b) of this section, as appropriate for each process unit, except as provided in paragraph (c) of this section: * * * * * (b) * * * (2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas) according to paragraph (b)(5) of this section. For gaseous fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00002 kg carbon per kg of gaseous fuel or feedstock, you may instead determine the carbon content and the molecular weight annually using the product specification’s maximum carbon content and molecular weight. For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), sample and analyze no less frequently than weekly to determine the carbon content and molecular weight of the fuel and feedstock according to paragraph (b)(5) of this section. (3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except PO 00000 Frm 00126 Fmt 4701 Sfmt 4700 annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) according to paragraph (b)(5) of this section. For liquid fuels and feedstocks that have a maximum product specification for carbon content less than or equal to 0.00006 kg carbon per gallon of liquid fuel or feedstock, you may instead determine the carbon content annually using the product specification’s maximum carbon content. (4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail) according to paragraph (b)(5) of this section. (5) Except as provided in paragraphs (b)(2) and (3) of this section for fuels and feedstocks with a carbon content below the specified levels, you must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5). * * * * * (xix) For fuels and feedstocks with a carbon content below the specified levels in paragraphs (b)(2) and (3) of this section, if the methods listed in paragraphs (b)(5)(i) through (xviii) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe, you may use modifications of the methods listed in paragraphs (b)(5)(i) through (xviii) or use other methods that are applicable to your fuel or feedstock. (c) You may use best available monitoring methods as specified in paragraph (c)(2) of this section for measuring the fuel used by each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater) that E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations meets the criteria specified in paragraph (c)(1) of this section. Eligibility to use best available monitoring methods ends upon the completion of any planned process unit or equipment shutdown after January 1, 2025. (1) To be eligible to use best available monitoring methods, you must meet all criteria in paragraphs (c)(1)(i) through (iv) of this section. (i) The stationary combustion unit must be directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater). (ii) A measurement device meeting the requirements in paragraph (b)(1) of this section is not installed to measure the fuel used by each stationary combustion unit as of January 1, 2025. (iii) The hydrogen production unit and associated stationary combustion unit are operated continuously. (iv) Installation of a measurement device to measure the fuel used by each stationary combustion unit that meets the requirements in paragraph (b)(1) of this section must require a planned process equipment or unit shutdown or can only be done through a hot tap. (2) Best available monitoring methods means any of the following methods: (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations. (iv) Other company records. ■ 46. Revise § 98.166 to read as follows: lotter on DSK11XQN23PROD with RULES2 § 98.166 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each hydrogen production process unit: (a) The unit identification number. (b) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under § 98.36 for the Tier 4 Calculation Methodology. If the CEMS measures emissions from either a common stack for multiple hydrogen production units or a common stack for hydrogen production unit(s) and other source(s), you must also report the estimated decimal fraction of the total annual CO2 emissions attributable to this hydrogen production process unit (estimated using engineering estimates or best available data). (c) If a material balance is used to calculate emissions using equations P– 1 through P–3 to § 98.163, as applicable, report the total annual CO2 emissions (metric tons) and the name and annual quantity (metric tons) of each carboncontaining fuel and feedstock. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (d) The information specified in paragraphs (d)(1) through (10): (1) The type of hydrogen production unit (steam methane reformer (SMR) only, SMR followed by water gas shift reaction (WGS), partial oxidation (POX) only, POX followed by WGS, autothermal reforming only, autothermal reforming followed by WGS, water electrolysis, brine electrolysis, other (specify)). (2) The type of hydrogen purification method (pressure swing adsorption, amine adsorption, membrane separation, other (specify), none). (3) Annual quantity of hydrogen produced by reforming, gasification, oxidation, reaction, or other transformation of feedstocks (metric tons). (4) Annual quantity of hydrogen that is purified only (metric tons). This quantity may be assumed to be equal to the annual quantity of hydrogen in the feedstocks to the hydrogen production unit. (5) Annual quantity of ammonia intentionally produced as a desired product, if applicable (metric tons). (6) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid forms, following the requirements of subpart PP of this part. (7) Annual quantity of carbon other than CO2 or methanol collected and transferred off site or transferred to a separate process unit within the facility for which GHG emissions associated with this carbon is being reported under other provisions of this part, in either gas, liquid, or solid forms (metric tons carbon). (8) Annual quantity of methanol intentionally produced as a desired product, if applicable, (metric tons) for each process unit. (9) Annual net quantity of steam consumed by the unit, (metric tons). Include steam purchased or produced outside of the hydrogen production unit. If the hydrogen production unit is a net producer of steam, enter the annual net quantity of steam consumed by the unit as a negative value. (10) An indication (yes or no) if best available monitoring methods were used, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater). If yes, report: (i) The beginning date of using best available monitoring methods, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., PO 00000 Frm 00127 Fmt 4701 Sfmt 4700 31927 reforming furnace and hydrogen production process unit heater). (ii) The anticipated or actual end date of using best available monitoring methods, as applicable, in accordance with § 98.164(c), to determine fuel flow for each stationary combustion unit directly associated with hydrogen production (e.g., reforming furnace and hydrogen production process unit heater). 47. Amend § 98.167 by: a. Revising paragraphs (a) and (b); ■ b. Removing and reserving paragraph (c); and ■ c. Revising paragraphs (d) and (e) introductory text. The revisions read as follows: ■ ■ § 98.167 Records that must be retained. * * * * * (a) If a CEMS is used to measure CO2 emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, and, if the CEMS measures emissions from a common stack for multiple hydrogen production units or emissions from a common stack for hydrogen production unit(s) and other source(s), records used to estimate the decimal fraction of the total annual CO2 emissions from the CEMS monitoring location attributable to each hydrogen production unit. (b) You must retain records of all analyses and calculations conducted to determine the values reported in § 98.166(b). * * * * * (d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage in § 98.163(b), including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (e) The applicable verification software records as identified in this paragraph (e). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (12) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (12) of this section for each hydrogen production unit. * * * * * E:\FR\FM\25APR2.SGM 25APR2 31928 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Subpart Q—Iron and Steel Production § 98.173 * 48. Amend § 98.173 by revising equation Q–5 in paragraph (b)(1)(v) to read as follows: ■ CO2 = :: * Calculating GHG emissions. * * (b) * * * (1) * * * (v) * * * * * [(Iron) * (Ciron) + (Scrap) * ( Cscrap) + (Flux) * (CF!ux) + (Electrode) * (Cmectrode) + (Carbon) * (Ccarbon) - (Eq. Q-5) * * * * * 49. Amend § 98.174 by: a. Revising paragraph (b)(2) introductory text; ■ b. Redesignating paragraph (b)(2)(vi) as paragraph (b)(2)(vii); and ■ c. Adding new paragraph (b)(2)(vi). The revision and addition read as follows: ■ ■ § 98.174 Monitoring and QA/QC requirements. * * * * * (b) * * * (2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in § 98.173(b)(1) based on analyses provided by the supplier, analyses provided by material recyclers who manage process outputs for sale or use by other industries, or by t Eco2,net = the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through (vii) of this section as applicable. * * * * * (vi) ASTM E415–17, Standard Test Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission Spectrometry (incorporated by reference, see § 98.7) as applicable for steel. * * * * * ■ 50. Amend § 98.176 by revising paragraphs (e)(2) and adding paragraph (g) to read as follows: § 98.193 § 98.176 * ■ * Data reporting requirements. * * (e) * * * * 12 II * b (EFLIME,i,n * MLIME,i,n) + i=1 n=1 (2) Whether the carbon content was determined from information from the supplier, material recycler, or by laboratory analysis, and if by laboratory analysis, the method used in § 98.174(b)(2). * * * * * (g) For each unit, the type of unit, the annual production capacity, and annual operating hours. * * * * * Subpart S—Lime Manufacturing 51. Amend § 98.193 by revising equation S–4 in paragraph (b)(2)(iv) to read as follows: Calculating GHG emissions. * * (b) * * * (2) * * * (iv) * * * * z 12 II * (EFLKD,i,n * MLKD,i,n) + i=1 n=1 L Ewaste,i i=1 * * * * ■ 52. Amend § 98.196 by: ■ a. Revising paragraph (a) introductory text; ■ b. Adding paragraphs (a)(9) through (14); ■ c. Revising paragraphs (b) introductory text and (b)(17); and ■ d. Adding paragraphs (b)(22) and (23). The revisions and additions read as follows: § 98.196 Data reporting requirements. lotter on DSK11XQN23PROD with RULES2 * * * * * (a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required by § 98.36 and the information listed in paragraphs (a)(1) through (14) of this section. * * * * * VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (9) Annual arithmetic average of calcium oxide content for each type of lime product produced (metric tons CaO/metric ton lime). (10) Annual arithmetic average of magnesium oxide content for each type of lime product produced (metric tons MgO/metric ton lime). (11) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste sold (metric tons CaO/metric ton lime). (12) Annual arithmetic average of magnesium oxide content for each type of calcined lime byproduct/waste sold (metric tons MgO/metric ton lime). (13) Annual arithmetic average of calcium oxide content for each type of calcined lime byproduct/waste not sold (metric tons CaO/metric ton lime). (14) Annual arithmetic average of magnesium oxide content for each type PO 00000 Frm 00128 Fmt 4701 Sfmt 4700 of calcined lime byproduct/waste not sold (metric tons MgO/metric ton lime) (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in paragraphs (b)(1) through (23) of this section. * * * * * (17) Indicate whether CO2 was captured and used on-site (e.g., for use in a purification process, the manufacture of another product). If CO2 was captured and used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section. (i) The annual amount of CO2 captured for use in all on-site processes. (ii) The method used to determine the amount of CO2 captured. * * * * * (22) Annual average results of chemical composition analysis of all lime byproducts or wastes not sold. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.040</GPH> * ER25AP24.041</GPH> (Eq. S--4) Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (23) Annual quantity (tons) of all lime byproducts or wastes not sold. Subpart U—Miscellaneous Uses of Carbonate 53. Amend § 98.210 by revising paragraph (b) to read as follows: ■ § 98.210 Definition of the source category. * * * * * (b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, zinc, or ceramics. * * * * * Subpart X-Petrochemical Production 54. Amend § 98.243 by revising paragraphs (b)(3) and (d)(5) to read as follows: ■ § 98.243 Calculating GHG emissions. * * * * * (b) * * * (3) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in § 98.253(b). * * * * * (d) * * * (5) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in § 98.253(b). ■ 55. Amend § 98.244 by revising paragraph (b)(4)(iii) to read as follows: § 98.244 Monitoring and QA/QC requirements. * * * * * (b) * * * (4) * * * (iii) ASTM D2505–88 (Reapproved 2004)e1 (incorporated by reference, see § 98.7). * * * * * ■ 56. Amend § 98.246 by revising paragraphs (a) introductory text, (a)(2), (5), (13) and (15), (b)(7) and (8), and (c) to read as follows: § 98.246 Data reporting requirements. lotter on DSK11XQN23PROD with RULES2 * * * * * (a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (15) of this section for each type of petrochemical produced, reported by process unit. * * * * * (2) The type of petrochemical produced. * * * * * (5) Annual quantity of each type of petrochemical produced from each VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the portion of the total amount of ethylene dichloride (EDC) produced that is used in vinyl chloride monomer (VCM) production may be a measured quantity or an estimate that is based on process knowledge and best available data. The portion of the total amount of EDC produced that is not utilized in VCM production must be measured in accordance with § 98.244(b)(2) or (3). Sum the amount of EDC used in the production of VCM plus the amount of separate EDC product to report as the total quantity of EDC petrochemical from an integrated EDC/VCM petrochemical process unit. * * * * * (13) Name and annual quantity (in metric tons) of each product included in equations X–1, X–2, and X–3 to § 98.243. If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/ vinyl chloride monomer process, the reported quantity of EDC product should include only that which was not used in the VCM process. * * * * * (15) For each gaseous feedstock or product for which the volume was used in equation X–1 to § 98.243, report the annual average molecular weight of the measurements or determinations, conducted according to § 98.243(c)(3) or (4). Report the annual average molecular weight in units of kg per kg mole. (b) * * * (7) Information listed in § 98.256(e) for each flare that burns process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO2, CH4 and N2O emissions that are attributable to combustion of off-gas from the petrochemical process unit(s) served by the flare. (8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). * * * * * (c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (6) of this section. (1) The ethylene process unit ID or other appropriate descriptor. (2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in § 98.36 for the applicable Tier methodology. For each stationary combustion unit or PO 00000 Frm 00129 Fmt 4701 Sfmt 4700 31929 group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit. (3) Information listed in § 98.256(e) for each flare that burns ethylene process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO2, CH4 and N2O emissions that are attributable to combustion of off-gas from the ethylene process unit(s) served by the flare. (4) Name and annual quantity of each carbon-containing feedstock (metric tons). (5) Annual quantity of ethylene produced from each process unit (metric tons). (6) Name and annual quantity (in metric tons) of each product produced in each process unit. Subpart Y—Petroleum Refineries 57. Amend § 98.250 by revising paragraph (c) to read as follows: ■ § 98.250 Definition of source category. * * * * * (c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; and sulfur recovery plants. § 98.252 [Amended] 58. Amend § 98.252 by removing and reserving paragraphs (e) and (i). ■ 59. Amend § 98.253 by: ■ a. Revising the introductory text of paragraphs (b) and (c); ■ b. Revising and republishing paragraphs (c)(4) and (5); ■ c. Revising paragraph (e) introductory text; ■ d. Removing and reserving paragraph (g); and ■ e. Revising and republishing paragraphs (i)(2) and (5). The revisions read as follows: ■ § 98.253 Calculating GHG emissions. * * * * * (b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations = (co 2 * EmF1 = Default CO2 emission factor for petroleum coke from table C–1 to subpart C of this part (kg CO2/MMBtu). EmF2 = Default CH4 emission factor for ‘‘PetroleumProducts’’ from table C–2 to subpart C of this part (kg CH4/MMBtu). Where: CH4 = Annual methane emissions from coke burn-off (metric tons CH4/year). CO2 = Emission rate of CO2 from coke burnoff calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this section, as applicable (metric tons/year). N O = (co * 2 2 Where: N2O = Annual nitrous oxide emissions from coke burn-off (mt N2O/year). CO2 = Emission rate of CO2 from coke burnoff calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this section, as applicable (metric tons/year). EmF1 = Default CO2 emission factor for petroleum coke from table C–1 to subpart C of this part (kg CO2/MMBtu). Mwater= Pwater X (Eq. Y-9) EmF2) EmF 1 (Eq. Y-10) EmF3) EmF1 EmF3 = Default N2O emission factor for ‘‘PetroleumProducts’’ from table C–2 to subpart C of this part (kg N2O/MMBtu). * * * * * (e) For catalytic reforming units, calculate the CO2 emissions from coke burn-off using the applicable methods described in paragraphs (e)(1) through (3) of this section and calculate the CH4 and N2O emissions using the methods (cttwater) X - Where: Mwater = Mass of water in the delayed coking unit vessel at the end of the cooling cycle just prior to atmospheric venting or draining (metric tons/cycle). ρwater = Density of water at average temperature of the delayed coking unit vessel at the end of the cooling cycle just prior to atmospheric venting (metric tons per cubic feet; mt/ft3). Use the default value of 0.0270 mt/ft3. Hwater = Typical distance from the bottom of the coking unit vessel to the top of the (5) Calculate N2O emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or equation Y– 10 to this section. TIXD 2 4- - described in paragraphs (c)(4) and (5) of this section, respectively. * * * * * (i) * * * (2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using equation Y–18b to this section. fcokeXMcoke) P (Eq. Y-18b) . particle water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates. fcoke = Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining. Use 1 if the water fully covers coke-filled portion of the coke drum. Mcoke = Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) as determined in paragraph (i)(1) of this section. ρparticle = Particle density of coke (metric tons per cubic feet; mt/ft3). Use the default value of 0.0382 mt/ft3. D = Diameter of delayed coking unit vessel (feet). * * * * * (5) Calculate the CH4 emissions from decoking operations at each delayed coking unit using equation Y–18f to this section. (Eq. Y-18f) lotter on DSK11XQN23PROD with RULES2 CH4 = Msteam X EmFocu X N X 0.001 Where: CH4 = Annual methane emissions from the delayed coking unit decoking operations (metric ton/year). Msteam = Mass of steam generated and released per decoking cycle (metric tons/ cycle) as determined in paragraph (i)(4) of this section. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 EmFDCU = Methane emission factor for delayed coking unit (kilograms CH4 per metric ton of steam; kg CH4/mt steam) from unit-specific measurement data. If you do not have unit-specific measurement data, use the default value of 7.9 kg CH4/metric ton steam. N = Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed PO 00000 Frm 00130 Fmt 4701 Sfmt 4700 coking unit vessels associated with the delayed coking unit during the year. 0.001 = Conversion factor (metric ton/kg). * * * * * 60. Amend § 98.254 by: a. Revising the introductory text of paragraphs (d) and (e); and ■ ■ E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.045</GPH> 4 in paragraphs (c)(1) through (5) of this section. * * * * * (4) Calculate CH4 emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or equation Y– 9 to this section. ER25AP24.044</GPH> CH malfunction events of 500,000 scf/day or less. * * * * * (c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions from coke burn-off using the applicable methods described ER25AP24.043</GPH> GHG emissions calculations with the exception of the following, which may be excluded as applicable: gas used for the flare pilots, and if using the calculation method in paragraph (b)(1)(iii) of this section, the gas released during start-up, shutdown, or ER25AP24.042</GPH> 31930 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations § 98.254 Monitoring and QA/QC requirements. * * * * * (d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic or direct mass spectrometer analysis of the gas may be used, provided that the gas chromatograph or mass spectrometer is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph or mass spectrometer are documented in the written Monitoring Plan for the unit under § 98.3(g)(5). * * * * * (e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the gas may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5). * * * * * § 98.255 [Amended] 61. Amend § 98.255 by removing and reserving paragraph (d). ■ 62. Amend § 98.256 by: ■ a. Removing and reserving paragraphs (b) and (i); ■ b. Adding paragraph (j)(2); and ■ c. Revising paragraph (k)(6). The addition and revision read as follows: ■ § 98.256 Data reporting requirements. * * * * (j) * * * (2) Maximum rated throughput of the unit, in metric tons asphalt/stream day. * * * * * (k) * * * (6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or lotter on DSK11XQN23PROD with RULES2 * calculated using equation Y–18a to § 98.253). If you use mass measurements from company records to determine the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle, you must also report: (i) Internal height of delayed coking unit vessel (feet) for each delayed coking unit. (ii) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed (i.e. , coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates for each delayed coking unit. * * * * * ■ 63. Amend § 98.257 by: ■ a. Revising paragraphs (b)(16) through (19); ■ b. Removing and reserving paragraphs (b)(27) through (31); ■ c. Revising paragraphs (b)(45), (46), and (53); and ■ d. Removing and reserving paragraphs (b)(54) through (56). The revisions read as follows: § 98.257 Records that must be retained. * * * * * (b) * * * (16) Value of unit-specific CH4 emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(4)). (17) Annual activity data (e.g. , input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(4)). (18) Value of unit-specific N2O emission factor, including the units of measure, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(5)). (19) Annual activity data (e.g. , input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, and catalytic reforming unit (calculation method in § 98.253(c)(5)). * * * * * (45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting or draining (metric ton/cycle) (equations Y–18b and Y–18e to § 98.253) for each delayed coking unit. (46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates (equation Y– 18b to § 98.253) for each delayed coking unit. * * * * * (53) Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining (equation Y–18b to § 98.253) for each delayed coking unit. * * * * * Subpart AA—Pulp and Paper Manufacturing 64. Revise and republish § 98.273 to read as follows: ■ § 98.273 Calculating GHG emissions. (a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO2, biogenic CO2, CH4, and N2O emissions using the procedures in paragraphs (a)(1) through (4) of this section. CH4 and N2O emissions must be calculated as the sum of emissions from combustion of fuels and combustion of biomass in spent liquor solids. (1) Calculate CO2 emissions from fuel combustion using direct measurement of fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO2 emissions if the respective monitoring and QA/QC requirements described in § 98.34 are met. (2) Calculate CH4 and N2O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO2 equivalent according to the methodology for stationary combustion sources in § 98.33(c). (3) Calculate biogenic CO2 emissions and emissions of CH4 and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default emissions factors, according to equation AA–1 to this section: CO 2 , CH 4 , or N2 0 from biomass= (0.90718) *Solids* HHV * EF Where: VerDate Sep<11>2014 CO2, CH4, or N2O, from Biomass = Biogenic CO2 emissions or emissions of CH4 or 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00131 Fmt 4701 Sfmt 4700 (Eq. AA-1) N2O from spent liquor solids combustion (metric tons per year). E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.046</GPH> b. Removing and reserving paragraphs (h) and (i). The revisions read as follows: ■ 31931 31932 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Biogenic CO 2 = 44 *Solids* CC* (0.90718) 12 Where: Biogenic CO2 = Annual CO2 mass emissions for spent liquor solids combustion (metric tons per year). Solids = Mass of the spent liquor solids combusted (short tons per year) determined according to § 98.274(b). CC = Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction, e.g. , 95% = 0.95). 44/12 = Ratio of molecular weights, CO2 to carbon. 0.90718 = Conversion from short tons to metric tons. (4) Calculate biogenic CO2 emissions from combustion of biomass (other than spent liquor solids) with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e). (c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO2, CH4, and N2O CO 2 = [ Mccaco lotter on DSK11XQN23PROD with RULES2 65. Amend § 98.276 by revising paragraph (a) to read as follows: ■ * * Data reporting requirements. * VerDate Sep<11>2014 * * 19:27 Apr 24, 2024 44 (Eq. AA-2) HHV listed in table C–1 to subpart C of this part and the default CH4 and N2O emissions factors listed in table AA–2 to this subpart. (3) Biogenic CO2 emissions from conversion of CaCO3 to CaO are included in the biogenic CO2 estimates calculated for the chemical recovery furnace in paragraph (a)(3) of this section. (4) Calculate biogenic CO2 emissions from combustion of biomass with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e). (d) For makeup chemical use, you must calculate CO2 emissions by using direct or indirect measurement of the quantity of chemicals added and ratios of the molecular weights of CO2 and the makeup chemicals, according to equation AA–3 to this section: ] • (Eq. AA-3) ) * -100 + M(Naco 3 ) * - * 1000 kg/metnc ton 105.99 Where: CO2 = CO2 mass emissions from makeup chemicals (kilograms/yr). M (CaCO3) = Make-up quantity of CaCO3 used for the reporting year (metric tons per year). M (NaCO3) = Make-up quantity of Na2CO3 used for the reporting year (metric tons per year). 44 = Molecular weight of CO2. 100 = Molecular weight of CaCO3. 105.99 = Molecular weight of Na2CO3. § 98.276 emissions using the procedures in paragraphs (c)(1) through (4) of this section: (1) Calculate CO2 emissions from fuel combustion using direct measurement of fuels consumed and default HHV and default emissions factors, according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO2 emissions if the respective monitoring and QA/QC requirements described in § 98.34 are met. (2) Calculate CH4 and N2O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO2 equivalent according to the methodology for stationary combustion sources in § 98.33(c); use the default 44 3 monitoring and QA/QC requirements described in § 98.34 are met. (2) Calculate CH4 and N2O emissions from fuel combustion using direct measurement of fuels consumed, default or site-specific HHV, and default emissions factors and convert to metric tons of CO2 equivalent according to the methodology for stationary combustion sources in § 98.33(c). (3) Calculate biogenic CO2 emissions using measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids, according to equation AA–2 to this section: Jkt 262001 (a) Annual emissions of CO2, biogenic CO2, CH4, and N2O (metric tons per year). * * * * * ■ 66. Amend § 98.277 by revising paragraph (d) to read as follows: § 98.277 Records that must be retained. * * * * * (d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for determining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online PO 00000 measurement system). If an online measurement system is used, you must retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements. * * * * * Frm 00132 Fmt 4701 Sfmt 4700 Subpart BB—Silicon Carbide Production 67. Amend § 98.286 by revising the introductory text and adding paragraph (c) to read as follows: ■ § 98.286 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.048</GPH> (4) Calculate biogenic CO2 emissions from combustion of biomass (other than spent liquor solids) with other fuels according to the applicable methodology for stationary combustion sources in § 98.33(e). (b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine CO2, CH4, and N2O emissions using the procedures in paragraphs (b)(1) through (5) of this section: (1) Calculate CO2 emissions from fuel combustion using direct measurement of fuels consumed and default emissions factors according to the Tier 1 Calculation Methodology for stationary combustion sources in § 98.33(a)(1). Tiers 2 or 3 from § 98.33(a)(2) or (3) may be used to calculate CO2 emissions if the respective ER25AP24.047</GPH> Solids = Mass of spent liquor solids combusted (short tons per year) determined according to § 98.274(b). HHV = Annual high heat value of the spent liquor solids (mmBtu per kilogram) determined according to § 98.274(b). EF = Default emission factor for CO2, CH4, or N2O, from table AA–1 to this subpart (kg CO2, CH4, or N2O per mmBtu). 0.90718 = Conversion factor from short tons to metric tons. Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each silicon carbide production facility. * * * * * (d) Records of all information reported as required under § 98.286(c). ■ 69. Revise and republish subpart DD consisting of §§ 98.300 through 98.308 to read as follows: Subpart DD—Electrical Transmission and Distribution Equipment Use Sec. 98.300 Definition of the source category. 98.301 Reporting threshold. 98.302 GHGs to report. 98.303 Calculating GHG emissions. 98.304 Monitoring and QA/QC requirements. 98.305 Procedures for estimating missing data. 98.306 Data reporting requirements. 98.307 Records that must be retained. 98.308 Definitions. § 98.300 Definition of the source category. (a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing fluorinated GHGs, including but not limited to sulfur hexafluoride (SF6) and perfluorocarbons (PFCs), used within an electric power system. Electric transmission and distribution equipment and servicing inventory includes, but is not limited to: (1) Gas-insulated substations. (2) Circuit breakers. (3) Switchgear, including closedpressure and hermetically sealedpressure switchgear and gas-insulated lines containing fluorinated GHGs, including but not limited to SF6 and PFCs. (4) Gas containers such as pressurized cylinders. (5) Gas carts. (6) Electric power transformers. (7) Other containers of fluorinated GHG, including but not limited to SF6 and PFCs. (b) [Reserved] § 98.301 E = Lj Li NCEPS,j * GHGi,w * GWPi * EF * 0.000453592 Where: E = Annual emissions for threshold applicability purposes (metric tons CO2e). NCEPS,j = the total nameplate capacity of equipment containing reportable insulating gas j (excluding hermetically sealed-pressure equipment) located within the facility plus the total nameplate capacity of equipment containing reportable insulting gas j (excluding hermetically sealed-pressure equipment) that is not located within the facility but is under common ownership or control (lbs). lotter on DSK11XQN23PROD with RULES2 E = Lj Li NCother,j * GHGi,w Where: E = Annual emissions for threshold applicability purposes (metric tons CO2e). VerDate Sep<11>2014 GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j in the gas insulated equipment included in the total nameplate capacity NCEPS,j, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1. i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 19:27 Apr 24, 2024 Jkt 262001 PO 00000 (Eq. DD-I) 0.000453592 = Conversion factor from lbs to metric tons. (b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in table A–3 or A– 4 to subpart A of this part is not required to report emissions under subpart DD of this part unless the total estimated emissions of fluorinated GHGs that are components of reportable insulating gases, as calculated in equation DD–2 to this section, equals or exceeds 25,000 tons CO2e. (Eq. DD-2) * GWPi * EF * 0.000453592 NCother,j = For a facility other than an electric power system, the total nameplate capacity of equipment containing reportable insulating gas j (excluding Frm 00133 Fmt 4701 Sfmt 4700 Reporting threshold. (a) You must report GHG emissions under this subpart if you are an electric power system as defined in § 98.308 and your facility meets the requirements of § 98.2(a)(1). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in table A–3 to subpart A to this part, you must calculate emissions of each fluorinated GHG that is a component of a reportable insulating gas and then sum the emissions of each fluorinated GHG resulting from the use of electrical transmission and distribution equipment for threshold applicability purposes using equation DD–1 to this section. hermetically sealed-pressure equipment) located within the facility (lbs). GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j in the gas insulated equipment included in E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.050</GPH> § 98.287 ER25AP24.049</GPH> in paragraph (a) or (b) of this section, and paragraph (c) of this section, as applicable for each silicon carbide production facility. * * * * * (c) If methane abatement technology is used at the silicon carbide production facility, you must report the information in paragraphs (c)(1) through (3) of this section. Upon reporting this information once in an annual report, you are not required to report this information again unless the information changes during a reporting year, in which case, the reporter must include any updates in the annual report for the reporting year in which the change occurred. (1) Type of methane abatement technology used on each silicon carbide process unit or production furnace, and date of installation for each. (2) Methane destruction efficiency for each methane abatement technology (percent destruction). You must either use the manufacturer’s specified destruction efficiency or the destruction efficiency determined via a performance test. If you report the destruction efficiency determined via a performance test, you must also report the test method that was used during the performance test. (3) Percentage of annual operating hours that methane abatement technology was in use for all silicon carbide process units or production furnaces combined. ■ 68. Amend § 98.287 by revising the introductory text and adding paragraph (d) to read as follows: 31933 31934 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations the total nameplate capacity NCother,j, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1. i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 0.000453592 = Conversion factor from lbs to metric tons. § 98.302 GHGs to report. You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, from your facility (including emissions from fugitive equipment leaks, installation, servicing, equipment decommissioning and disposal, and from storage cylinders) resulting from the transmission and distribution servicing inventory and equipment listed in § 98.300(a), except you are not required to report emissions of fluorinated GHGs that are components of insulating gases whose weighted average GWPs, as calculated in equation DD–3 to this section, are less than or equal to one. For acquisitions of equipment containing or insulated with fluorinated GHGs, you must report emissions from the equipment after the title to the equipment is transferred to the electric power transmission or distribution entity. (Eq. DD-3) Where: GWPj = Weighted average GWP of insulating gas j. GHGi,w = The weight fraction of GHG i in insulating gas j, expressed as a decimal. fraction. If GHG i is not part of a gas mixture, use a value of 1.0. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. i = GHG contained in the electrical transmission and distribution equipment. § 98.303 Calculating GHG emissions. (a) Calculating GHG emissions. Calculate the annual emissions of each fluorinated GHG that is a component of any reportable insulating gas using the mass-balance approach in equation DD– 4 to this section: User Emissionsi = Ij GHGi,w * [(Decrease in Inventory of Reportable Insulating Gas j) + (Acquisitions of Reportable Insulating Gasj)-(Disbursements of Reportable Insulating Gasj)(Net Increase in Total Nameplate Capacity of Equipment Operated Containing Reportable (Eq. DD--4) VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 returned to facility after off-site recycling) + (Pounds of reportable insulating gas j acquired inside equipment, except hermetically sealedpressure switchgear, that was transferred while the equipment was in use, e.g., through acquisition of all or part of another electric power system). Disbursements of Reportable Insulating gas j = (Pounds of reportable insulating gas j returned to suppliers) + (Pounds of reportable insulating gas j sent off site for recycling) + (Pounds of reportable insulating gas j sent off-site for destruction) + (Pounds of reportable insulating gas j that was sold or transferred to other entities in bulk) + (Pounds of reportable insulating gas j contained in equipment, including hermetically sealed-pressure switchgear, that was sold or transferred to other entities while the equipment was not in use) + (Pounds of reportable insulating gas j inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., through sale of all or part of the electric power system to another electric power system). Net Increase in Total Nameplate Capacity of Equipment Operated containing reportable insulating gas j = (The Nameplate Capacity of new equipment, PO 00000 Frm 00134 Fmt 4701 Sfmt 4700 as defined at § 98.308, containing reportable insulating gas j in pounds)¥(Nameplate Capacity of retiring equipment, as defined at § 98.308, containing reportable insulating gas j in pounds). (Note that Nameplate Capacity refers to the full and proper charge of equipment rather than to the actual charge, which may reflect leakage). (b) Nameplate capacity adjustments. Users of closed-pressure electrical equipment with a voltage capacity greater than 38 kV may measure and adjust the nameplate capacity value specified by the equipment manufacturer on the nameplate attached to that equipment, or within the equipment manufacturer’s official product specifications, by following the requirements in paragraphs (b)(1) through (10) of this section. Users of other electrical equipment are not permitted to adjust the nameplate capacity value of the other equipment. (1) If you elect to measure the nameplate capacity value(s) of one or more pieces of electrical equipment with a voltage capacity greater than 38 kV, you must measure the nameplate capacity values of all the electrical E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.052</GPH> Where: User Emissionsi = Emissions of fluorinated GHG i from the facility (pounds). GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j if reportable insulating gas j is a gas mixture, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0. Decrease in Inventory of Reportable Insulating Gas j = (Pounds of reportable insulating gas j stored in containers, but not in energized equipment, at the beginning of the year)¥(Pounds of reportable insulating gas j stored in containers, but not in energized equipment, at the end of the year). Reportable insulating gas inside equipment that is not energized is considered to be ‘‘stored in containers.’’ Acquisitions of Reportable Insulating gas j = (Pounds of reportable insulating gas j purchased or otherwise acquired from chemical producers, chemical distributors, or other entities in bulk) + (Pounds of reportable insulating gas j purchased or otherwise acquired from equipment manufacturers, equipment distributors, or other entities with or inside equipment, including hermetically sealed-pressure switchgear, while the equipment was not in use) + (Pounds of each SF6 insulating gas j ER25AP24.051</GPH> lotter on DSK11XQN23PROD with RULES2 Insulating Gas j)] Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations time, transfer the insulating gas to the equipment to reach the temperaturecompensated design operating pressure per manufacturer specifications. Follow the manufacturer-specified procedure to ensure that the measured temperature accurately reflects the temperature of the insulating gas, e.g., by measuring the insulating gas pressure and vessel temperature after allowing appropriate time for the temperature of the transferred gas to equilibrate with the vessel temperature. Measure and calculate the total amount of reportable insulating gas added to the device using one of the methods specified in paragraphs (b)(4)(ii)(A) and (B) of this section. (A) To determine the amount of reportable insulating gas transferred to the electrical equipment, weigh the gas container being used to fill the device prior to, and after, the addition of the reportable insulating gas to the electrical equipment, and subtract the second value (after-transfer gas container weight) from the first value (prior-totransfer gas container weight). Account for any gas contained in hoses before and after the transfer. (B) Connect a mass flow meter between the electrical equipment and a gas cart. Transfer gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. During gas transfer, you must keep the mass flow rate within the range specified by the mass flow meter manufacturer to assure an accurate and precise mass flow meter reading. Close the connection to the GIE from the mass flow meter hose and ensure that the gas trapped in the filling hose returns through the mass flow meter. Calculate the amount of gas transferred from the mass reading on the mass flow meter. (iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain the measured nameplate capacity for the new equipment. (5) Electrical equipment users measuring the nameplate capacity of any retiring electrical equipment must: (i) Measure and record the initial system pressure and vessel temperature prior to removing any insulating gas. (ii) Compare the initial system pressure and temperature to the equipment manufacturer’s temperature/ pressure curve for that equipment and insulating gas. (iii) If the temperature-compensated initial system pressure of the electrical equipment does not match the temperature-compensated design operating pressure specified by the equipment manufacturer, you may either: (A) Add or remove insulating gas to/ from the electrical equipment until the manufacturer-specified value is reached, or (B) If the temperature-compensated initial system pressure of the electrical equipment is no higher than the temperature-compensated design operating pressure specified by the manufacturer and no lower than five pounds per square inch (5 psi) less than the temperature-compensated design operating pressure specified by the manufacturer, use equation DD–5 to this section to calculate the nameplate capacity based on the mass recorded under paragraph (b)(5)(vi) of this section. (iv) Weigh the gas container being used to receive the gas and record this value. (v) Recover insulating gas from the electrical equipment until five minutes after the pressure in the electrical equipment reaches a pressure of at most five pounds per square inch absolute (5 psia). (vi) Record the amount of insulating gas recovered (pounds) by weighing the gas container that received the gas and subtracting the weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section from this value. Account for any gas contained in hoses before and after the transfer. The amount of gas recovered shall be the measured nameplate capacity for the electrical equipment unless the final temperaturecompensated pressure of the electrical equipment exceeds 0.068 psia (3.5 Torr) or the electrical equipment user is calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, in which cases the measured nameplate capacity shall be the result of equation DD–5 to this section. (vii) If you are calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, use equation DD–5 to this section to do so. (Eq. DD-5) VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00135 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.053</GPH> lotter on DSK11XQN23PROD with RULES2 equipment in your facility that has a voltage capacity greater than 38 kV and that is installed or retired in that reporting year and in subsequent reporting years. (2) You must adopt the measured nameplate capacity value for any piece of equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer equals or exceeds two percent of the nameplate capacity value most recently specified by the manufacturer. (3) You may adopt the measured nameplate capacity value for equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer, but if you elect to adopt the measured nameplate capacity for that equipment, then you must adopt the measured nameplate capacity value for all of the equipment for which the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer. This applies in the reporting year in which you first adopt the measured nameplate capacity for the equipment and in subsequent reporting years. (4) Users of electrical equipment measuring the nameplate capacity of any new electrical equipment must: (i) Record the amount of insulating gas in the equipment at the time the equipment was acquired (pounds), either per information provided by the manufacturer, or by transferring insulating gas from the equipment to a gas container and measuring the amount of insulating gas transferred. The equipment user is responsible for ensuring the gas is accounted for consistent with the methodologies specified in paragraphs (b)(4)(ii) through (iii) and (b)(5) of this section. If no insulating gas was in the device when it was acquired, record this value as zero. (ii) If insulating gas is added to the equipment subsequent to the acquisition of the equipment to energize it the first 31935 lotter on DSK11XQN23PROD with RULES2 31936 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Where: NCC = Nameplate capacity of the equipment measured and calculated by the equipment user (pounds). Pi = Initial temperature-compensated pressure of the equipment, based on the temperature-pressure curve for the insulating gas (psia). Pf = Final temperature-compensated pressure of the equipment, based on the temperature-pressure curve for the insulating gas (psia). This may be equated to zero if the final temperaturecompensated pressure of the equipment is equal to or lower than 0.068 psia (3.5 Torr). PNC = Temperature-compensated pressure of the equipment at the manufacturerspecified filling density of the equipment (i.e., at the full and proper charge, psia). MR = Mass of insulating gas recovered from the equipment, measured in paragraph (b)(5)(vi) of this section (pounds). paragraph (b) must meet the following accuracy and precision requirements: (i) Flow meters must be certified by the manufacturer to be accurate and precise to within one percent of the largest value that the flow meter can, according to the manufacturer’s specifications, accurately record. (ii) Pressure gauges must be certified by the manufacturer to be accurate and precise to within 0.5% of the largest value that the gauge can, according to the manufacturer’s specifications, accurately record. (iii) Temperature gauges must be certified by the manufacturer to be accurate and precise to within +/¥1.0 °F. (iv) Scales must be certified by the manufacturer to be accurate and precise to within one percent of the true weight. (viii) Record the final system pressure and vessel temperature. (6) Instead of measuring the nameplate capacity of electrical equipment when it is retired, users may measure the nameplate capacity of electrical equipment during maintenance activities that require opening the gas compartment, but they must follow the procedures set forth in paragraph (b)(5) of this section. (7) If the electrical equipment will remain energized, and the electrical equipment user is adopting the usermeasured nameplate capacity, the electrical equipment user must affix a revised nameplate capacity label, showing the revised nameplate value and the year the nameplate capacity adjustment process was performed, to the device by the end of the calendar year in which the process was completed. The manufacturer’s previous nameplate capacity label must remain visible after the revised nameplate capacity label is affixed to the device. (8) For each piece of electrical equipment whose nameplate capacity was adjusted during the reporting year, the revised nameplate capacity value must be used in all provisions wherein the nameplate capacity is required to be recorded, reported, or used in a calculation in this subpart unless otherwise specified herein. (9) The nameplate capacity of a piece of electrical equipment may only be adjusted more than once if the physical capacity of the device has changed (e.g., replacement of bushings) after the initial adjustment was performed, in which case the equipment user must adjust the nameplate capacity pursuant to the provisions of this paragraph (b). (10) Measuring devices used to measure the nameplate capacity of electrical equipment under this § 98.304 Monitoring and QA/QC requirements. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (a) [Reserved] (b) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting: (1) Review inputs to equation DD–4 to § 98.303 to ensure inputs and outputs to the company’s system are included. (2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in fluorinated GHG Inventory and the Net Increase in Total Nameplate Capacity may be calculated as negative numbers. (3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year. (4) Ensure that in addition to fluorinated GHG purchased from bulk gas distributors, fluorinated GHG purchased from Original Equipment Manufacturers (OEM) and fluorinated GHG returned to the facility from offsite recycling are also accounted for among the total additions. (c) Ensure the following QA/QC methods are employed throughout the year: (1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer’s specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ±2 pounds, of residual gas amounts in the cylinders returned to the gas supplier. (2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale PO 00000 Frm 00136 Fmt 4701 Sfmt 4700 that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer’s specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer. (3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system). (d) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. § 98.305 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for fluorinated GHGs, and from similar equipment repair, replacement, and maintenance operations. § 98.306 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical: (a) Nameplate capacity of equipment (pounds) containing each insulating gas: (1) Existing at the beginning of the year (excluding hermetically sealedpressure switchgear). (2) New hermetically sealed-pressure switchgear during the year. (3) New equipment other than hermetically sealed-pressure switchgear during the year. (4) Retired hermetically sealedpressure switchgear during the year. (5) Retired equipment other than hermetically sealed-pressure switchgear during the year. (b) Transmission miles (length of lines carrying voltages above 35 kilovolts). (c) Distribution miles (length of lines carrying voltages at or below 35 kilovolts). (d) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the beginning of the year. (e) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the end of the year. E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (f) Pounds of each reportable insulating gas purchased or otherwise acquired in bulk from chemical producers, chemical distributors, or other entities. (g) Pounds of each reportable insulating gas purchased or otherwise acquired from equipment manufacturers, equipment distributors, or other entities with or inside equipment, including hermetically sealed-pressure switchgear, while the equipment was not in use. (h) Pounds of each reportable insulating gas returned to facility after off-site recycling. (i) Pounds of each reportable insulating gas acquired inside equipment, except hermetically sealedpressure switchgear, that was transferred while the equipment was in use, e.g., through acquisition of all or part of another electric power system. (j) Pounds of each reportable insulating gas returned to suppliers. (k) Pounds of each reportable insulating gas that was sold or transferred to other entities in bulk. (l) Pounds of each reportable insulating gas sent off-site for recycling. (m) Pounds of each reportable insulating gas sent off-site for destruction. (n) Pounds of each reportable insulating gas contained in equipment, including hermetically sealed-pressure switchgear, that was sold or transferred to other entities while the equipment was not in use. (o) Pounds of each reportable insulating gas disbursed inside equipment, except hermetically sealedpressure switchgear, that was transferred while the equipment was in use, e.g., through sale of all or part of the electric power system to another electric power system. (p) State(s) or territory in which the facility lies. (q) The number of reportableinsulating-gas-containing pieces of equipment in each of the following equipment categories: (1) New hermetically sealed-pressure switchgear during the year. (2) New equipment other than hermetically sealed-pressure switchgear during the year. (3) Retired hermetically sealedpressure switchgear during the year. (4) Retired equipment other than hermetically sealed-pressure switchgear during the year. (r) The total of the nameplate capacity values most recently assigned by the electrical equipment manufacturer(s) to each of the following groups of equipment: (1) All new equipment whose nameplate capacity values were VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 measured by the user under this subpart and for which the user adopted the usermeasured nameplate capacity value during the year. (2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the usermeasured nameplate capacity value during the year. (s) The total of the nameplate capacity values measured by the electrical equipment user for each of the following groups of equipment: (1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the usermeasured nameplate capacity value during the year. (2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the usermeasured nameplate capacity value during the year. (t) For each reportable insulating gas reported in paragraphs (a), (d) through (o), and (q) of this section, an ID number or other appropriate descriptor that is unique to that reportable insulating gas. (u) For each ID number or descriptor reported in paragraph (t) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas. § 98.307 Records that must be retained. (a) In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306. (b) For each piece of electrical equipment whose nameplate capacity is measured by the equipment user, retain records of the following: (1) Equipment manufacturer name. (2) Year equipment was manufactured. If the date year the equipment was manufactured cannot be determined, report a best estimate of the year of manufacture and record how the estimated year was determined. (3) Manufacturer serial number. For any piece of equipment whose serial number is unknown (e.g., the serial number does not exist or is not visible), another unique identifier must be recorded as the manufacturer serial number. The electrical equipment user must retain documentation that allows for each electrical equipment to be readily identifiable. (4) Equipment type (i.e., closedpressure vs. hermetically sealedpressure). (5) Equipment voltage capacity (in kilovolts). PO 00000 Frm 00137 Fmt 4701 Sfmt 4700 31937 (6) The name and GWP of each insulating gas used. (7) Nameplate capacity value (pounds), as specified by the equipment manufacturer. The value must reflect the latest value specified by the manufacturer during the reporting year. (8) Nameplate capacity value (pounds) measured by the equipment user. (9) The date the nameplate capacity measurement process was completed. (10) The measurements and calculations used to calculate the value in paragraph (b)(8) of this section. (11) The temperature-pressure curve and/or other information used to derive the initial and final temperatureadjusted pressures of the equipment. (12) Whether or not the nameplate capacity value in paragraph (b)(8) of this section has been adopted for the piece of electrical equipment. § 98.308 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Facility, with respect to an electric power system, means the electric power system as set out in this definition. An electric power system is comprised of all electric transmission and distribution equipment insulated with or containing fluorinated GHGs that is linked through electric power transmission or distribution lines and functions as an integrated unit, that is owned, serviced, or maintained by a single electric power transmission or distribution entity (or multiple entities with a common owner), and that is located between: (1) The point(s) at which electric energy is obtained from an electricity generating unit or a different electric power transmission or distribution entity that does not have a common owner; and (2) The point(s) at which any customer or another electric power transmission or distribution entity that does not have a common owner receives the electric energy. The facility also includes servicing inventory for such equipment that contains fluorinated GHGs. Electric power transmission or distribution entity means any entity that transmits, distributes, or supplies electricity to a consumer or other user, including any company, electric cooperative, public electric supply corporation, a similar Federal department (including the Bureau of Reclamation or the Corps of Engineers), a municipally owned electric department offering service to the E:\FR\FM\25APR2.SGM 25APR2 lotter on DSK11XQN23PROD with RULES2 31938 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations public, an electric public utility district, or a jointly owned electric supply project. Energized, for the purposes of this subpart, means connected through busbars or cables to an electrical power system or fully-charged, ready for service, and being prepared for connection to the electrical power system. Energized equipment does not include spare gas insulated equipment (including hermetically-sealed pressure switchgear) in storage that has been acquired by the facility, and is intended for use by the facility, but that is not being used or prepared for connection to the electrical power system. Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc-quenching gas in electrical equipment. New equipment, for the purposes of this subpart, means either any gas insulated equipment, including hermetically-sealed pressure switchgear, that is not energized at the beginning of the reporting year but is energized at the end of the reporting year, or any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been added to the facility’s inventory without being taken out of active service (e.g., when the equipment is sold to or acquired by the facility while remaining in place and continuing operation). Operator, for the purposes of this subpart, means any person who operates or supervises a facility, excluding a person whose sole responsibility is to ensure reliability, balance load or otherwise address electricity flow. Reportable insulating gas, for purposes of this subpart, means an insulating gas whose weighted average GWP, as calculated in equation DD–3 to § 98.302, is greater than one. A fluorinated GHG that makes up either part or all of a reportable insulating gas is considered to be a component of the reportable insulating gas. Retired equipment, for the purposes of this subpart, means either any gas insulated equipment including hermetically-sealed pressure switchgear, that is energized at the beginning of the reporting year but is not energized at the end of the reporting year, or any gas insulated equipment other than hermetically-sealed pressure switchgear that has been transferred while in use, meaning it has been removed from the VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 facility’s inventory without being taken out of active service (e.g., when the equipment is acquired by a new facility while remaining in place and continuing operation). Subpart FF—Underground Coal Mines 70. Amend § 98.323 by revising parameter ‘‘MCFi’’ of equation FF–3 in paragraph (b) introductory text to read as follows: ■ § 98.323 * Calculating GHG emissions. * * (b) * * * * * MCFi = Moisture correction factor for the measurement period, volumetric basis. = 1 when Vi and Ci are measured on a dry basis or if both are measured on a wet basis. = 1¥(fH2O)i when Vi is measured on a wet basis and Ci is measured on a dry basis. = 1/[1¥(fH2O)i] when Vi is measured on a dry basis and Ci is measured on a wet basis. * * * * * 71. Amend § 98.326 by revising paragraph (t) to read as follows: ■ § 98.326 Data reporting requirements. * * * * * (t) Mine Safety and Health Administration (MSHA) identification number for this coal mine. Subpart GG—Zinc Production 72. Amend § 98.333 by revising paragraph (b)(1) introductory text to read as follows: ■ § 98.333 Calculating GHG emissions. * * * * * (b) * * * (1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO2 process emissions from each affected unit at your facility using equation GG– 1 to this section. For electrothermic furnaces, carbon containing input materials include carbon electrodes and carbonaceous reducing agents. For Waelz kilns, carbon containing input materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the PO 00000 Frm 00138 Fmt 4701 Sfmt 4700 material in your calculation using equation R–1 to § 98.183. * * * * * ■ 73. Amend § 98.336 by adding paragraphs (a)(6) and (b)(6) to read as follows: § 98.336 Data reporting requirements. * * * * * (a) * * * (6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons). (b) * * * (6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons). * * * * * Subpart HH—Municipal Solid Waste Landfills 74. Amend § 98.343 by revising paragraphs (a)(2) and (c)(3) to read as follows: ■ § 98.343 Calculating GHG emissions. (a) * * * (2) For years when material-specific waste quantity data are available, apply equation HH–1 to this section for each waste quantity type and sum the CH4 generation rates for all waste types to calculate the total modeled CH4 generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF, DOCF, and F shown in table HH–1 to this subpart. The annual quantity of each type of waste disposed must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the uncharacterized MSW parameters for a portion of your waste materials when using the material-specific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter values for k and DOC in table HH–1 to this subpart for the total quantity of waste disposed in those years. * * * * * (c) * * * (3) For landfills with landfill gas collection systems, calculate CH4 emissions using the methodologies specified in paragraphs (c)(3)(i) and (ii) of this section. (i) Calculate CH4 emissions from the modeled CH4 generation and measured CH4 recovery using equation HH–6 to this section. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Where: Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4). GCH4 = Modeled methane generation rate in reporting year from equation HH–1 to this section or the quantity of recovered CH4 from equation HH–4 to this section, whichever is greater (metric tons CH4). N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destruction devices, then N = 1. Rn = Quantity of recovered CH4 from equation HH–4 to this section for the nth measurement location (metric tons CH4). OX = Oxidation fraction. Use the appropriate oxidation fraction default value from table HH–4 to this subpart. DEn = Destruction efficiency (lesser of manufacturer’s specified destruction efficiency and 0.99) for the nth X (1 - ox)] (Eq. HH-7) foest,n))}] (Eq. HH-8) Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH4). Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4). C = Number of landfill gas collection systems operated at the landfill. X = Number of landfill gas measurement locations associated with landfill gas collection system ‘‘c’’. N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destruction devices, then N = 1. Note that N = S(c=1)C[S(x=1)X[1]]. Rx,c = Quantity of recovered CH4 from equation HH–4 to this section for the xth measurement location for landfill gas collection system ‘‘c’’ (metric tons CH4). Rn = Quantity of recovered CH4 from equation HH–4 to this section for the nth measurement location (metric tons CH4). CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, measurement practices, and cover system materials VerDate Sep<11>2014 (ii) Calculate CH4 generation and CH4 emissions using measured CH4 recovery and estimated gas collection efficiency and equations HH–7 and HH–8 to this section. 19:27 Apr 24, 2024 Jkt 262001 from table HH–3 to this subpart. If area by soil cover type information is not available, use applicable default value for CE4 in table HH–3 to this subpart for all areas under active influence of the collection system. fRec,c = Fraction of hours the landfill gas collection system ‘‘c’’ was operating normally (annual operating hours/8760 hours per year or annual operating hours/8784 hours per year for a leap year). Do not include periods of shutdown or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances, in the annual operating hours. OX = Oxidation fraction. Use appropriate oxidation fraction default value from table HH–4 to this subpart. DEn = Destruction efficiency, (lesser of manufacturer’s specified destruction efficiency and 0.99) for the nth measurement location. If the gas is transported off-site for destruction, use DE = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate DEn as the PO 00000 Frm 00139 Fmt 4701 Sfmt 4700 arithmetic average of the DE values determined for each destruction device associated with that measurement location. fDest,n = Fraction of hours the destruction device associated with the nth measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device. The annual operating hours for the destruction device should include only those periods when flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation. For flares, times when there is no flame present must be excluded from the annual operating hours for the destruction device. If the gas is transported off-site for destruction, use fDest,n = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined for each destruction device E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.055</GPH> lotter on DSK11XQN23PROD with RULES2 (DEn = [2L~=1 [L~=l Rx,c] X CE fRec,c intended temperature or other parameter indicative of effective operation. For flares, times when there is no flame present must be excluded from the annual operating hours for the destruction device. If the gas is transported off-site for destruction, use fDest,n = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate fDest,n as the arithmetic average of the fDest values determined for each destruction device associated with that measurement location. ER25AP24.054</GPH> MG measurement location. If the gas is transported off-site for destruction, use DE = 1. If the volumetric flow and CH4 concentration of the recovered gas is measured at a single location providing landfill gas to multiple destruction devices (including some gas destroyed on-site and some gas sent off-site for destruction), calculate DEn as the arithmetic average of the DE values determined for each destruction device associated with that measurement location. fDest,n = Fraction of hours the destruction device associated with the nth measurement location was operating during active gas flow calculated as the annual operating hours for the destruction device divided by the annual hours flow was sent to the destruction device. The annual operating hours for the destruction device should include only those periods when flow was sent to the destruction device and the destruction device was operating at its 31939 31940 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations associated with that measurement location. 75. Amend § 98.346 by: a. Redesignating paragraphs (h) and (i) as paragraphs (i) and (j), respectively. ■ b. Adding new paragraph (h); and ■ c. Revising newly redesignated paragraphs (j)(5) through (7). The addition and revisions read as follows: ■ ■ § 98.346 Data reporting requirements. * * * * * (h) An indication of the applicability of part 60 or part 62 of this chapter requirements to the landfill (part 60, subparts WWW and XXX of this chapter, approved state plan implementing part 60, subparts Cc or Cf of this chapter, Federal plan as implemented at part 62, subparts GGG or OOO of this chapter, or not subject to part 60 or part 62 of this chapter municipal solid waste landfill rules), and if the landfill is subject to a part 60 or part 62 of this chapter municipal solid waste landfill rule, an indication of whether the landfill gas collection system is required under part 60 or part 62 of this chapter. * * * * * (j) * * * (5) The number of gas collection systems at the landfill facility. (6) For each gas collection system at the facility report: (i) A unique name or ID number for the gas collection system. (ii) A description of the gas collection system (manufacturer, capacity, and number of wells). (iii) The annual hours the gas collection system was operating normally. Do not include periods of shut down or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances, in the annual operating hours. (iv) The number of measurement locations associated with the gas collection system. (v) For each measurement location associated with the gas collection system, report: (A) A unique name or ID number for the measurement location. (B) Annual quantity of recovered CH4 (metric tons CH4) calculated using equation HH–4 to § 98.343. (C) An indication of whether destruction occurs at the landfill facility, off-site, or both for the measurement location. (D) If destruction occurs at the landfill facility for the measurement location (in full or in part), also report the number of destruction devices associated with the measurement location that are located at the landfill facility and the information in paragraphs (j)(6)(v)(D)(1) through (6) of this section for each destruction device located at the landfill facility. (1) A unique name or ID number for the destruction device. (2) The type of destruction device (flare, a landfill gas to energy project (i.e., engine or turbine), off-site, or other (specify)). (3) The destruction efficiency (decimal). (4) The total annual hours where active gas flow was sent to the destruction device. (5) The annual operating hours where active gas flow was sent to the destruction device and the destruction device was operating at its intended temperature or other parameter indicative of effective operation. For flares, times when there is no flame present must be excluded from the annual operating hours for the destruction device. (6) The estimated fraction of the recovered CH4 reported for the measurement location directed to the destruction device based on best available data or engineering judgement (decimal, must total to 1 for each measurement location). (7) The following information about the landfill. (i) The surface area (square meters) and estimated waste depth (meters) for each area specified in table HH–3 to this subpart. (ii) The estimated gas collection system efficiency for the landfill. (iii) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at the landfill. * * * * * 76. Revise table HH–1 to subpart HH to read as follows: ■ TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS lotter on DSK11XQN23PROD with RULES2 Factor Default value DOC and k values—Bulk waste option: DOC (bulk waste) for disposal years prior to 2010 ............... DOC (bulk waste) for disposal years 2010 and later ............ k (precipitation plus recirculated leachate a <20 inches/year) for disposal years prior to 2010. k (precipitation plus recirculated leachate a <20 inches/year) for disposal years 2010 and later. k (precipitation plus recirculated leachate a 20–40 inches/ year) for disposal years prior to 2010. k (precipitation plus recirculated leachate a 20–40 inches/ year) for disposal years 2010 and later. k (precipitation plus recirculated leachate a >40 inches/year) for disposal years prior to 2010. k (precipitation plus recirculated leachate a >40 inches/year) for disposal years 2010 and later. DOC and k values—Modified bulk MSW option: DOC (bulk MSW, excluding inerts and C&D waste) for disposal years prior to 2010. DOC (bulk MSW, excluding inerts and C&D waste) for disposal years 2010 and later. DOC (inerts, e.g., glass, plastics, metal, concrete) ............... DOC (C&D waste) ................................................................. k (bulk MSW, excluding inerts and C&D waste) for disposal years prior to 2010. k (bulk MSW, excluding inerts and C&D waste) for disposal years 2010 and later. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00140 Units 0.20 ............................................................ 0.17 ............................................................ 0.02 ............................................................ Weight fraction, wet basis. Weight fraction, wet basis. yr–1. 0.033 .......................................................... yr–1. 0.038 .......................................................... yr–1. 0.067 .......................................................... yr–1. 0.057 .......................................................... yr–1. 0.098 .......................................................... yr–1. 0.31 ............................................................ Weight fraction, wet basis. 0.27 ............................................................ Weight fraction, wet basis. 0.00 ............................................................ 0.08 ............................................................ 0.02 to 0.057 b ............................................ Weight fraction, wet basis. Weight fraction, wet basis. yr–1. 0.033 to 0.098 b .......................................... yr–1. Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31941 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued Factor Default value Units k (inerts, e.g., glass, plastics, metal, concrete) ..................... k (C&D waste) ....................................................................... DOC and k values—Waste composition option: DOC (food waste) .................................................................. DOC (garden) ........................................................................ DOC (paper) .......................................................................... DOC (wood and straw) .......................................................... DOC (textiles) ........................................................................ DOC (diapers) ........................................................................ DOC (sewage sludge) ........................................................... DOC (inerts, e.g., glass, plastics, metal, cement) ................. DOC (Uncharacterized MSW ................................................ k (food waste) ........................................................................ k (garden) .............................................................................. k (paper) ................................................................................ k (wood and straw) ................................................................ k (textiles) .............................................................................. k (diapers) .............................................................................. k (sewage sludge) ................................................................. k (inerts, e.g., glass, plastics, metal, concrete) ..................... k (uncharacterized MSW) ...................................................... Other parameters—All MSW landfills: MCF ....................................................................................... DOCF ..................................................................................... F ............................................................................................. OX .......................................................................................... DE .......................................................................................... 0.00 ............................................................ 0.02 to 0.04 b .............................................. yr–1. yr–1. 0.15 ............................................................ 0.2 .............................................................. 0.4 .............................................................. 0.43 ............................................................ 0.24 ............................................................ 0.24 ............................................................ 0.05 ............................................................ 0.00 ............................................................ 0.32 ............................................................ 0.06 to 0.185 c ............................................ 0.05 to 0.10 c .............................................. 0.04 to 0.06 c .............................................. 0.02 to 0.03 c .............................................. 0.04 to 0.06 c .............................................. 0.05 to 0.10 c .............................................. 0.06 to 0.185 c ............................................ 0.00 ............................................................ 0.033 to 0.098 b .......................................... Weight Weight Weight Weight Weight Weight Weight Weight Weight yr–1. yr–1. yr–1. yr–1. yr–1. yr–1. yr–1. yr–1. yr–1. fraction, fraction, fraction, fraction, fraction, fraction, fraction, fraction, fraction, wet wet wet wet wet wet wet wet wet basis. basis. basis. basis. basis. basis. basis. basis. basis. 1. 0.5. 0.5. See table HH–4 to this subpart. 0.99. a Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates divided by the area of the portion of the landfill containing waste with appropriate unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of 0.098 rather than calculating the recirculated leachate rate. b Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive). Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than calculating the recirculated leachate rate. c Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate or recirculated leachate rate. 77. Revise table HH–3 to subpart HH to read as follows: ■ TABLE HH–3 TO SUBPART HH OF PART 98—LANDFILL GAS COLLECTION EFFICIENCIES lotter on DSK11XQN23PROD with RULES2 Description Term ID Landfill gas collection efficiency A1: Area with no waste in-place ................................................................................................................................. Not applicable; do not use this area in the calculation. A2: Area without active gas collection, regardless of cover type .............................................................................. A3: Area with daily soil cover and active gas collection ............................................................................................ A4: Area with an intermediate soil cover, or a final soil cover not meeting the criteria for A5 below, and active gas collection. A5: Area with a final soil cover of 3 feet or thicker of clay or final cover (as approved by the relevant agency) and/or geomembrane cover system and active gas collection. CE2 .............. CE3 .............. CE4 .............. 0%. 50%. 65%. CE5 .............. 85%. Area weighted average collection efficiency for landfills ............................................................................................ CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2 + A3 + A4 + A5). 78. Revise footnote ‘‘b’’ to table HH— 4 to subpart HH to read as follows: ■ VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00141 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 31942 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations TABLE HH–4 TO SUBPART HH OF PART 98—LANDFILL METHANE OXIDATION FRACTIONS Use this landfill methane oxidation fraction: Under these conditions: * * * * * * * * * * * * * * b Methane flux rate (in grams per square meter per day; g/m2/d) is the mass flow rate of methane per unit area at the bottom of the surface soil prior to any oxidation and is calculated as follows: For equation HH–5 to § 98.343, or for equation TT–6 to § 98.463, MF = K × GCH4/SArea For equation HH–6 to § 98.343, For equation HH–7 to § 98.343, MF = K X (~ L~=l [L~=l Rx,c])/sarea CE fRec,c For equation HH–8 to § 98.343, VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00142 Fmt 4701 Sfmt 4700 Subpart OO—Suppliers of Industrial Greenhouse Gases 79. Amend § 98.416 by revising paragraphs (c) introductory text, (c)(6) and (7), (d) introductory text, and (d)(4), and adding paragraph (k) to read as follows: ■ § 98.416 Data reporting requirements. * * * * * (c) Each bulk importer of fluorinated GHGs, fluorinated heat transfer fluids (HTFs), or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except importers may exclude shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the importer also excludes transshipments from reporting of exports under paragraph (d) of this section; and heels that meet the conditions set forth at § 98.417(e) if the importer also excludes heels from any reporting of exports under paragraph (d) of this section. The report shall contain E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.058</GPH> C = Number of landfill gas collection systems operated at the landfill. X = Number of landfill gas measurement locations associated with landfill gas collection system ‘‘c’’. N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH4 concentration of the recovered gas sent to one or multiple destruction devices, then N = 1. Note that N = Sc=1C[Sx=1X[1]]. Rx,c = Quantity of recovered CH4 from equation HH–4 to § 98.343 for the xth measurement location for landfill gas collection system ‘‘c’’ (metric tons CH4). Rn = Quantity of recovered CH4 from equation HH–4 to § 98.343 for the nth measurement location (metric tons CH4). fRec,c = Fraction of hours the landfill gas collection system ‘‘c’’ was operating normally (annual operating hours/8,760 hours per year or annual operating hours/8,784 hours per year for a leap year). Do not include periods of shutdown or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances, in the annual operating hours. ER25AP24.057</GPH> Where: MF = Methane flux rate from the landfill in the reporting year (grams per square meter per day, g/m2/d). K = unit conversion factor = 106/365 (g/ metric ton per days/year) or 106/366 for a leap year. SArea = The surface area of the landfill containing waste at the beginning of the reporting year (square meters, m2). GCH4 = Modeled methane generation rate in reporting year from equation HH–1 to § 98.343 or equation TT–1 to § 98.463, as applicable, except for application with equation HH–6 to § 98.343 (metric tons CH4). For application with equation HH– 6 to § 98.343, the greater of the modeled methane generation rate in reporting year from equation HH–1 to § 98.343 or equation TT–1 to § 98.463, as applicable, and the quantity of recovered CH4 from equation HH–4 to § 98.343 (metric tons CH4). CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, measurement practices, and cover system materials from table HH–3 to this subpart. If area by soil cover type information is not available, use applicable default value for CE4 in table HH–3 to this subpart for all areas under active influence of the collection system. ER25AP24.056</GPH> lotter on DSK11XQN23PROD with RULES2 MF = K X (~EL..c-1 "'c_ [L~=l Rx,c] - L..n-1 "'N- Rn )/sarea fRec,c C Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations the following information for each import: * * * * * (6) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped. (7) Customs entry number and importer number for each shipment. * * * * * (d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except reporters may exclude shipments including less than twentyfive kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the exporter also excludes transshipments from reporting of imports under paragraph (c) of this section; and heels if the exporter also excludes heels from any reporting of imports under paragraph (c) of this section. The report shall contain the following information for each export: * * * * * (4) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped. * * * * * (k) For nitrous oxide, saturated perfluorocarbons, sulfur hexafluoride, and fluorinated heat transfer fluids as defined at § 98.6, report the end use(s) for which each GHG or fluorinated HTF is transferred and the aggregated annual quantity of that GHG or fluorinated HTF in metric tons that is transferred to that end use application, if known. Subpart PP—Suppliers of Carbon Dioxide 80. Amend § 98.420 by adding paragraph (a)(4) to read as follows: ■ § 98.420 Definition of the source category. lotter on DSK11XQN23PROD with RULES2 (a) * * * (4) Facilities with process units, including but not limited to direct air capture (DAC), that capture a CO2 stream from ambient air for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground. * * * * * ■ 81. Amend § 98.422 by adding paragraph (e) to read as follows: § 98.422 GHGs to report. * * * * * (e) Mass of CO2 captured from DAC process units. (1) Mass of CO2 captured from ambient air. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (2) Mass of CO2 captured from any onsite heat and/or electricity generation, where applicable. ■ 82. Amend § 98.423 by revising paragraphs (a)(3)(i) introductory text and (a)(3)(ii) introductory text to read as follows: § 98.423 Calculating CO2 supply. (a) * * * (3) * * * (i) For facilities with production process units, DAC process units, or production wells that capture or extract a CO2 stream and either measure it after segregation or do not segregate the flow, calculate the total CO2 supplied in accordance with equation PP–3a to paragraph (a)(3)(i) of this section. * * * * * (ii) For facilities with production process units or DAC process units that capture a CO2 stream and measure it ahead of segregation, calculate the total CO2 supplied in accordance with equation PP–3b to paragraph (a)(3)(ii) of this section. * * * * * ■ 83. Amend § 98.426 by: ■ a. Redesignating paragraphs (f)(12) and (13) as paragraphs (f)(13) and (14), respectively; ■ b. Adding new paragraph (f)(12); ■ c. Revising paragraph (h); and ■ d. Adding paragraph (i). The additions and revision read as follows: § 98.426 Data reporting requirements. * * * * * (f) * * * (12) Geologic sequestration of carbon dioxide with enhanced oil recovery that is covered by subpart VV of this part. * * * * * (h) If you capture a CO2 stream from a facility that is subject to this part and transfer CO2 to any facilities that are subject to subpart RR or VV of this part, you must: (1) Report the facility identification number associated with the annual GHG report for the facility that is the source of the captured CO2 stream; (2) Report each facility identification number associated with the annual GHG reports for each subpart RR and subpart VV facility to which CO2 is transferred; and (3) Report the annual quantity of CO2 in metric tons that is transferred to each subpart RR and subpart VV facility. (i) If you capture a CO2 stream at a facility with a DAC process unit, report the annual quantity of on-site and offsite electricity and heat generated for each DAC process unit as specified in paragraphs (i)(1) through (3) of this PO 00000 Frm 00143 Fmt 4701 Sfmt 4700 31943 section. The quantities specified in paragraphs (i)(1) through (3) of this section must be provided per energy source if known and must represent the electricity and heat used for the DAC process unit starting with air intake and ending with the compressed CO2 stream (i.e., the CO2 stream ready for supply for commercial applications or, if maintaining custody of the stream, sequestration or injection of the stream underground). (1) Electricity excluding combined heat and power (CHP). If electricity is provided to a dedicated meter for the DAC process unit, report the annual quantity of electricity consumed, in megawatt hours (MWh), and the information in paragraph (i)(1)(i) or (ii) of this section. (i) If the electricity is sourced from a grid connection, report the following information: (A) State where the facility with the DAC process unit is located. (B) County where the facility with the DAC process unit is located. (C) Name of the electric utility company that supplied the electricity as shown on the last monthly bill issued by the utility company during the reporting period. (D) Name of the electric utility company that delivered the electricity. In states with regulated electric utility markets, this will generally be the same utility reported under paragraph (i)(1)(i)(C) of this section, but in states with deregulated electric utility markets, this may be a different utility company. (E) Annual quantity of electricity consumed in MWh, calculated as the sum of the total energy usage values specified in all billing statements received during the reporting year. Most customers will receive 12 monthly billing statements during the reporting year. Many utilities bill their customers per kilowatt-hour (kWh); usage values on bills that are based on kWh should be divided by 1,000 to report the usage in MWh as required under this paragraph (i)(1)(i)(E). (ii) If electricity is sourced from onsite or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(1)(ii)(A) through (G) of this section, report the annual quantity of electricity consumed, in MWh. If the on-site electricity source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit. (A) Non-hydropower renewable sources including solar, wind, geothermal and tidal. (B) Hydropower. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. (2) Heat excluding CHP. For each applicable energy source specified in paragraphs (i)(2)(i) through (vii) of this section, report the annual quantity of heat, steam, or other forms of thermal energy sourced from on-site or through a contractual mechanism for dedicated off-site generation, in megajoules (MJ). If the on-site heat source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit. (i) Solar. (ii) Geothermal. (iii) Natural gas. (iv) Oil. (v) Coal. (vi) Nuclear. (vii) Other. (3) CHP—(i) Electricity from CHP. If electricity from CHP is sourced from onsite or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(3)(i)(A) through (G) of this section, report the annual quantity consumed, in MWh. If the on-site electricity source for CHP is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit. (A) Non-hydropower renewable sources including solar, wind, geothermal and tidal. (B) Hydropower. (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. (ii) Heat from CHP. For each applicable energy source specified in paragraphs (i)(3)(ii)(A) through (G) of this section, report the quantity of heat, steam, or other forms of thermal energy from CHP sourced from on-site or through a contractual mechanism for dedicated off-site generation, in MJ. If the on-site heat source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit. (A) Solar. lotter on DSK11XQN23PROD with RULES2 E = Lj Li~ 19:27 Apr 24, 2024 § 98.427 Records that must be retained. * * * * * (a) The owner or operator of a facility containing production process units or DAC process units must retain quarterly records of captured or transferred CO2 streams and composition. * * * * * Subpart QQ—Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams 85. Amend § 98.436 by adding paragraphs (a)(7) and (b)(7) to read as follows: ■ § 98.436 Data reporting requirements. (a) * * * (7) The Harmonized tariff system (HTS) code for each type of pre-charged equipment or closed-cell foam imported. (b) * * * (7) The Schedule B code for each type of pre-charged equipment or closed-cell foam exported. Subpart RR—Geologic Sequestration of Carbon Dioxide 86. Amend § 98.449 by adding the definition ‘‘Offshore’’ in alphabetical order to read as follows: ■ § 98.449 Definitions. * * * * * Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act. * * * * * ■ 87. Revise subpart SS consisting of §§ 98.450 through 98.458 to read as follows: Subpart SS—Electrical Equipment Manufacture or Refurbishment Sec. 98.450 Definition of the source category. 98.451 Reporting threshold. 98.452 GHGs to report. 98.453 Calculating GHG emissions. 98.454 Monitoring and QA/QC requirements. 98.455 Procedures for estimating missing data. 98.456 Data reporting requirements. 98.457 Records that must be retained. 98.458 Definitions. § 98.450 Jkt 262001 Pj = Total annual purchases of reportable insulating gas j (lbs). GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j if reportable insulating gas j is a gas mixture. If not a mixture, use 1. PO 00000 Frm 00144 Fmt 4701 Sfmt 4700 Definition of the source category. The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gascontaining components of such equipment) containing fluorinated GHGs, including but not limited to sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs). The processes include equipment testing, installation, manufacturing, decommissioning and disposal, refurbishing, and storage in gas cylinders and other containers. § 98.451 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in § 98.2(a)(2), follow the requirements of § 98.2(b), with one exception. Instead of following the requirement of § 98.453 to calculate emissions from electrical equipment manufacture or refurbishment, you must calculate emissions of each fluorinated GHG that is a component of a reportable insulating gas and then sum the emissions of each fluorinated GHG resulting from manufacturing and refurbishing electrical equipment using equation SS–1 to this section. (Eq. SS-1) * GHGi,w * GWPi * EF * 0.000453592 Where: E = Annual production process emissions for threshold applicability purposes (metric tons CO2e). VerDate Sep<11>2014 (B) Geothermal. (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. ■ 84. Amend § 98.427 by revising paragraph (a) to read as follows: GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs purchased). For all gases, use an emission factor of 0.1. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.059</GPH> 31944 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 0.000453592 = Conversion factor from lbs to metric tons. § 98.452 GHGs to report. (a) You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, at the facility level, except you are not required to report emissions of fluorinated GHGs that are components of insulating gases whose weighted average GWPs, as calculated in equation SS–2 to this section, are less than or equal to one. You are, however, required to report certain quantities of insulating gases whose weighted average GWPs are less than or equal to one as specified in § 98.456(f), (g), (k) and (q) through (s). 31945 Annual emissions from the facility must include fluorinated GHG emissions from equipment that is installed at an off-site electric power transmission or distribution location whenever emissions from installation activities (e.g., filling) occur before the title to the equipment is transferred to the electric power transmission or distribution entity. (Eq. SS-2) Where: GWPj = Weighted average GWP of insulating gas j. GHGi,w = The weight fraction of GHG i in insulating gas j, expressed as a decimal. fraction. If GHG i is not part of a gas mixture, use a value of 1.0. GWPi = Gas-appropriate GWP as provided in table A–1 to subpart A of this part. i = GHG contained in the electrical transmission and distribution equipment. (b) You must report CO2, N2O and CH4 emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part by following the requirements of subpart C of this part. § 98.453 Calculating GHG emissions. (a) For each electrical equipment manufacturer or refurbisher, estimate the annual emissions of each fluorinated GHG that is a component of any reportable insulating gas using the massbalance approach in equation SS–3 to this section: User emissionsi = rjGHGi,w * [(Decrease in Inventory of Reportable Insulating Gas j Inventory)+ (Acquisitions of Reportable Insulating Gasj)- (Disbursements of Reportable Insulating Gasj)] Where: User emissionsi = Annual emissions of each fluorinated GHG i (pounds). GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j if insulating gas j is a gas mixture, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0. Decrease in Inventory of Reportable Insulating Gas j Inventory = (Pounds of reportable insulating gas j stored in containers at the beginning of the year)— (Pounds of reportable insulating gas j stored in containers at the end of the year). Acquisitions of Reportable Insulating Gas j = (Pounds of reportable insulating gas j purchased from chemical producers or suppliers in bulk) + (Pounds of reportable insulating gas j returned by equipment users) + (Pounds of reportable insulating gas j returned to site after offsite recycling). Disbursements of Reportable Insulating Gas j = (Pounds of reportable insulating gas j contained in new equipment delivered to customers) + (Pounds of reportable insulating gas j delivered to equipment users in containers) + (Pounds of (Eq. SS-3) reportable insulating gas j returned to suppliers) + (Pounds of reportable insulating gas j sent off site for recycling) + (Pounds of reportable insulating gas j sent off-site for destruction). (b) [Reserved] (c) Estimate the disbursements of reportable insulating gas j sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers using equation SS–4 to this section: VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (d) Estimate the mass of each insulating gas j disbursed to customers in new equipment or cylinders over the period p by monitoring the mass flow of each insulating gas j into the new equipment or cylinders using a flowmeter, or by weighing containers before and after gas from containers is PO 00000 Frm 00145 Fmt 4701 Sfmt 4700 used to fill equipment or cylinders, or by using the nameplate capacity of the equipment. (e) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is estimated by weighing containers before and after gas from containers is used to fill equipment or cylinders, estimate this quantity using equation SS–5 to this section: E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.062</GPH> for recycling, for destruction or to be returned to suppliers. n = The number of periods in the year. ER25AP24.061</GPH> Where: DGHG = The annual disbursement of reportable insulating gas j sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers. Qp = The mass of reportable insulating gas j charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including ER25AP24.060</GPH> lotter on DSK11XQN23PROD with RULES2 (Eq. SS--4) 31946 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (Eq. SS-5) Where: Qp = The mass of insulating gas j charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers. MB = The mass of the contents of the containers used to fill equipment or cylinders at the beginning of period p. ME = The mass of the contents of the containers used to fill equipment or cylinders at the end of period p. EL = The mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled). (f) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined using a flowmeter, estimate this quantity using equation SS–6 to this section: (Eq. SS-6) Where: Qp = The mass of insulating gas j charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers. Mmr = The mass of insulating gas j that has flowed through the flowmeter during the period p. EL EL = The mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment that is being filled). = LJ=o Fci * EFci Where: EL = The mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled). FCi = The total number of fill operations over the period p for the valve-hose combination Ci. EFCi = The emission factor for the valve-hose combination Ci. n=The number of different valve-hose combinations C used during the period p. (g) Estimate the mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled) using equation SS–7 to this section: (Eq. SS-7) (h) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined by using the nameplate capacity, or by using the nameplate capacity of the equipment and calculating the partial shipping charge, use the methods in either paragraph (h)(1) or (2) of this section. (1) Determine the equipment’s actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f). (2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge. (i) Estimate the annual emissions of reportable insulating gas j from the equipment that is installed at an off-site electric power transmission or distribution location before the title to the equipment is transferred by using equation SS–8 to this section: VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 § 98.454 Monitoring and QA/QC requirements. (a) [Reserved] (b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and PO 00000 Frm 00146 Fmt 4701 Sfmt 4700 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.066</GPH> precision of ±1 percent of full scale or better or scales with an accuracy and precision of ±1 percent of the filled weight (gas plus tare) of the containers of each reportable insulating gas that are typically weighed on the scale. For scales that are generally used to weigh cylinders containing 115 pounds of gas when full, this equates to ±1 percent of the sum of 115 pounds and approximately 120 pounds tare, or slightly more than ±2 pounds. Account for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier (e.g., for the contents of cylinders containing ER25AP24.065</GPH> MC = The total annual mass of reportable insulating gas j, in pounds, used to charge the equipment prior to leaving the electrical equipment manufacturer facility. NI = The total annual nameplate capacity of the equipment, in pounds, installed at electric transmission or distribution facilities. ER25AP24.064</GPH> Where: EI = Total annual emissions of reportable insulating gas j from equipment installation at electric transmission or distribution facilities. GHGi,w = The weight fraction of fluorinated GHG i in reportable insulating gas j if reportable insulating gas j is a gas mixture, expressed as a decimal fraction. If the GHG i is not part of a gas mixture, use a value of 1.0. MF = The total annual mass of reportable insulating gas j, in pounds, used to fill equipment during equipment installation at electric transmission or distribution facilities. ER25AP24.063</GPH> lotter on DSK11XQN23PROD with RULES2 Eq.SS-8 lotter on DSK11XQN23PROD with RULES2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations new gas or for the heels remaining in cylinders returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however, you remain responsible for the accuracy of these masses and weights under this subpart. (c) All flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities under this subpart must be calibrated using calibration procedures specified by the flowmeter, scale, volumetric or density measure equipment manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer. (d) For purposes of equation SS–7 to § 98.453, the emission factor for the valve-hose combination (EFC) must be estimated using measurements and/or engineering assessments or calculations based on chemical engineering principles or physical or chemical laws or properties. Such assessments or calculations may be based on, as applicable, the internal volume of hose or line that is open to the atmosphere during coupling and decoupling activities, the internal pressure of the hose or line, the time the hose or line is open to the atmosphere during coupling and decoupling activities, the frequency with which the hose or line is purged and the flow rate during purges. You must develop a value for EFc (or use an industry-developed value) for each combination of hose and valve fitting, to use in equation SS–7 to § 98.453. The value for EFC must be determined for each combination of hose and valve fitting of a given diameter or size. The calculation must be recalculated annually to account for changes to the specifications of the valves or hoses that may occur throughout the year. (e) Electrical equipment manufacturers and refurbishers must account for emissions of each reportable insulating gas that occur as a result of unexpected events or accidental losses, such as a malfunctioning hose or leak in the flow line, during the filling of equipment or containers for disbursement by including these losses in the estimated mass of each reportable insulating gas emitted downstream of the container or flowmeter during the period p. (f) If the mass of each reportable insulating gas j disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment’s nameplate capacity or, in cases where equipment is shipped VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 with a partial charge, equal to its partial shipping charge, equipment samples for conducting the nameplate capacity tests must be selected using the following stratified sampling strategy in this paragraph (f). For each make and model, group the measurement conditions to reflect predictable variability in the facility’s filling practices and conditions (e.g., temperatures at which equipment is filled). Then, independently select equipment samples at random from each make and model under each group of conditions. To account for variability, a certain number of these measurements must be performed to develop a robust and representative average nameplate capacity (or shipping charge) for each make, model, and group of conditions. A Student T distribution calculation should be conducted to determine how many samples are needed for each make, model, and group of conditions as a function of the relative standard deviation of the sample measurements. To determine a sufficiently precise estimate of the nameplate capacity, the number of measurements required must be calculated to achieve a precision of one percent of the true mean, using a 95 percent confidence interval. To estimate the nameplate capacity for a given make and model, you must use the lowest mean value among the different groups of conditions, or provide justification for the use of a different mean value for the group of conditions that represents the typical practices and conditions for that make and model. Measurements can be conducted using SF6, another gas, or a liquid. Re-measurement of nameplate capacities should be conducted every five years to reflect cumulative changes in manufacturing methods and conditions over time. (g) Ensure the following QA/QC methods are employed throughout the year: (1) Procedures are in place and followed to track and weigh all cylinders or other containers at the beginning and end of the year. (2) [Reserved] (h) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting: (1) Review inputs to equation SS–3 to § 98.453 to ensure inputs and outputs to the company’s system are included. (2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in the inventory for each reportable insulating gas may be calculated as negative. (3) Ensure that for each reportable insulating gas, the beginning-of-year inventory matches the end-of-year inventory from the previous year. PO 00000 Frm 00147 Fmt 4701 Sfmt 4700 31947 (4) Ensure that for each reportable insulating gas, in addition to the reportable insulating gas purchased from bulk gas distributors, the reportable insulating gas returned from equipment users with or inside equipment and the reportable insulating gas returned from off-site recycling are also accounted for among the total additions. § 98.455 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from similar manufacturing operations, and from similar equipment testing and decommissioning activities for which data are available. § 98.456 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each chemical at the facility level: (a) Pounds of each reportable insulating gas stored in containers at the beginning of the year. (b) Pounds of each reportable insulating gas stored in containers at the end of the year. (c) Pounds of each reportable insulating gas purchased in bulk. (d) Pounds of each reportable insulating gas returned by equipment users with or inside equipment. (e) Pounds of each reportable insulating gas returned to site from off site after recycling. (f) Pounds of each insulating gas inside new equipment delivered to customers. (g) Pounds of each insulating gas delivered to equipment users in containers. (h) Pounds of each reportable insulating gas returned to suppliers. (i) Pounds of each reportable insulating gas sent off site for destruction. (j) Pounds of each reportable insulating gas sent off site to be recycled. (k) The nameplate capacity of the equipment, in pounds, delivered to customers with each insulating gas inside, if different from the quantity in paragraph (f) of this section. (l) A description of the engineering methods and calculations used to determine emissions from hoses or other flow lines that connect the container to the equipment that is being filled. (m) The values for EFci of equation SS–7 to § 98.453 for each hose and valve combination and the associated valve fitting sizes and hose diameters. E:\FR\FM\25APR2.SGM 25APR2 31948 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations (n) The total number of fill operations for each hose and valve combination, or, FCi of equation SS–7 to § 98.453. (o) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the mean value of nameplate capacity in pounds for each make, model, and group of conditions. (p) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the number of samples and the upper and lower bounds on the 95-percent confidence interval for each make, model, and group of conditions. (q) Pounds of each insulating gas used to fill equipment at off-site electric power transmission or distribution locations, or MF, of equation SS–8 to § 98.453. (r) Pounds of each insulating gas used to charge the equipment prior to leaving the electrical equipment manufacturer or refurbishment facility, or MC, of equation SS–8 to § 98.453. (s) The nameplate capacity of the equipment, in pounds, installed at offsite electric power transmission or distribution locations used to determine emissions from installation, or NI, of equation SS–8 to § 98.453. (t) For any missing data, you must report the reason the data were missing, the parameters for which the data were missing, the substitute parameters used to estimate emissions in their absence, and the quantity of emissions thereby estimated. (u) For each insulating gas reported in paragraphs (a) through (j) and (o) through (r) of this section, an ID number or other appropriate descriptor unique to that insulating gas. (v) For each ID number or descriptor reported in paragraph (u) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas. lotter on DSK11XQN23PROD with RULES2 § 98.457 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the following records: (a) All information reported and listed in § 98.456. (b) Accuracy certifications and calibration records for all scales and monitoring equipment, including the method or manufacturer’s specification used for calibration. (c) Certifications of the quantity of gas, in pounds, charged into equipment at the electrical equipment VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 manufacturer or refurbishment facility as well as the actual quantity of gas, in pounds, charged into equipment at installation. (d) Check-out and weigh-in sheets and procedures for cylinders. (e) Residual gas amounts, in pounds, in cylinders sent back to suppliers. (f) Invoices for gas purchases and sales. (g) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. § 98.458 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part. Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc-quenching gas in electrical equipment. Reportable insulating gas, for purposes of this subpart, means an insulating gas whose weighted average GWP, as calculated in equation SS–2 to § 98.452, is greater than one. A fluorinated GHG that makes up either part or all of a reportable insulating gas is considered to be a component of the reportable insulating gas. Subpart UU—Injection of Carbon Dioxide 88. Revise and republish § 98.470 to read as follows: ■ § 98.470 Definition of the source category. (a) The injection of carbon dioxide (CO2) source category comprises any well or group of wells that inject a CO2 stream into the subsurface. (b) If you report under subpart RR of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells. (c) If you report under subpart VV of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells. If you previously met the source category definition for subpart UU of this part for a project where CO2 is injected in enhanced recovery operations for oil and other hydrocarbons (CO2–EOR) and then began using the standard designated as CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) such that you met the definition of the source category for subpart VV during a reporting year, you must report under subpart UU for the portion of the year before you began using CSA/ANSI ISO 27916:19 and report under subpart VV for the portion of the year after you began using CSA/ANSI ISO 27916:19. PO 00000 Frm 00148 Fmt 4701 Sfmt 4700 (d) A facility that is subject to this part only because it is subject to subpart UU of this part is not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2). ■ 89. Add subpart VV consisting of §§ 98.480 through 98.489, subpart WW consisting of §§ 98.490 through 98.498, subpart XX consisting of §§ 98.500 through 98.508, subpart YY consisting of §§ 98.510 through 98.518, and subpart ZZ consisting of §§ 98.520 through 98.528 to part 98 to read as follows: Subpart VV—Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916 Sec. 98.480 Definition of the source category. 98.481 Reporting threshold. 98.482 GHGs to report. 98.483 Calculating CO2 geologic sequestration. 98.484 Monitoring and QA/QC requirements. 98.485 Procedures for estimating missing data. 98.486 Data reporting requirements. 98.487 Records that must be retained. 98.488 EOR Operations Management Plan. 98.489 Definitions. § 98.480 Definition of the source category. (a) This source category pertains to carbon dioxide (CO2) that is injected in enhanced recovery operations for oil and other hydrocarbons (CO2–EOR) in which all of the following apply: (1) You are using the standard designated as CSA/ANSI ISO 27916:19, (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO2 in association with EOR operations. (2) You are not reporting under subpart RR of this part. (b) This source category does not include wells permitted as Class VI under the Underground Injection Control program. (c) If you are subject to only this subpart, you are not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2). § 98.481 Reporting threshold. (a) You must report under this subpart if your CO2–EOR project uses CSA/ ANSI ISO 27916:19 (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO2 in association with CO2–EOR operations. There is no threshold for reporting. (b) The requirements of § 98.2(i) do not apply to this subpart. Once a CO2– EOR project becomes subject to the E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations requirements of this subpart, you must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports until the facility has met the requirements of paragraphs (b)(1) and (2) of this section and submitted a notification to discontinue reporting according to paragraph (b)(3) of this section. (1) Discontinuation of reporting under this subpart must follow the requirements set forth under Clause 10 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (2) CO2–EOR project termination is completed when all of the following occur: (i) Cessation of CO2 injection. (ii) Cessation of hydrocarbon production from the project reservoir; and (iii) Wells are plugged and abandoned unless otherwise required by the appropriate regulatory authority. (3) You must notify the Administrator of your intent to cease reporting and provide a copy of the CO2–EOR project termination documentation. (c) If you previously met the source category definition for subpart UU of this part for your CO2–EOR project and then began using CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO2 in association with CO2–EOR operations during a reporting year, you must report under subpart UU of this part for the portion of the year before you began using CSA/ANSI ISO 27916:19 and report under subpart VV for the portion of the year after you began using CSA/ ANSI ISO 27916:19. 19:27 Apr 24, 2024 § 98.483 Calculating CO2 geologic sequestration. You must calculate CO2 sequestered using the following quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (a) You must calculate the mass of CO2 stored in association with CO2–EOR (mstored) in the reporting year by subtracting the mass of CO2 loss from operations and the mass of CO2 loss from the EOR complex from the total mass of CO2 input (as specified in equation 1 to this paragraph (a)). Equation 1 to paragraph (a) mstored = minput¥mloss operations¥mloss EOR complex Where: mstored = The annual quantity of associated storage in metric tons of CO2 mass. minput = The total mass of CO2 mreceived by the EOR project plus mnative (see Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) and paragraph (c) of this section), metric tons. Native CO2 produced and captured in the CO2–EOR project (mnative) can be quantified and included in minput. mloss operations = The total mass of CO2 loss from project operations (see Clauses 8.4.1 through 8.4.5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7) and paragraph (d) of this section), metric tons. mloss EOR complex = The total mass of CO2 loss from the EOR complex (see Clause 8.4.6 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)), metric tons. (b) The manner by which associated storage is quantified must assure completeness and preclude double counting. The annual mass of CO2 that is recycled and reinjected into the EOR complex must not be quantified as associated storage. Loss from the CO2 recycling facilities must be quantified. (c) You must quantify the total mass of CO2 input (minput) in the reporting year according to paragraphs (g)(1) through (3) of this section. (1) You must include the total mass of CO2 received at the custody transfer meter by the CO2–EOR project (mreceived). (2) The CO2 stream received (including CO2 transferred from another CO2–EOR project) must be metered. (i) The native CO2 recovered and included as mnative must be documented. (ii) CO2 delivered to multiple CO2– EOR projects must be allocated among those CO2–EOR projects. (3) The sum of the quantities of allocated CO2 must not exceed the total quantities of CO2 received. (d) You must calculate the total mass of CO2 from project operations (mloss operations) in the reporting year as specified in equation 2 to this paragraph (d). Equation 2 to paragraph (d) = m1oss leakage facilites + mloss flare vent + m1oss entrained + m1oss transfer Where: mloss leakage facilities = Loss of CO2 due to leakage from production, handling, and recycling CO2–EOR facilities (infrastructure including wellheads), metric tons. mloss vent/flare = Loss of CO2 from venting/ flaring from production operations, metric tons. mloss entrained = Loss of CO2 due to entrainment within produced gas/oil/water when this CO2 is not separated and reinjected, metric tons. mloss transfer=Loss of CO2 due to any transfer of CO2 outside the CO2–EOR project, metric tons. You must quantify any CO2 that is subsequently produced from the EOR complex and transferred offsite. VerDate Sep<11>2014 GHGs to report. You must report the following from Clause 8 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7): (a) The mass of CO2 received by the CO2–EOR project. (b) The mass of CO2 loss from the CO2–EOR project operations. (c) The mass of native CO2 produced and captured. (d) The mass of CO2 produced and sent off-site. (e) The mass of CO2 loss from the EOR complex. (f) The mass of CO2 stored in association with CO2–EOR. Jkt 262001 § 98.486 § 98.484 Monitoring and QA/QC requirements. You must use the applicable monitoring and quality assurance requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). § 98.485 Procedures for estimating missing data. Whenever the value of a parameter is unavailable or the quality assurance procedures set forth in § 98.484 cannot be followed, you must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). PO 00000 Frm 00149 Fmt 4701 Sfmt 4700 Data reporting requirements. In addition to the information required by § 98.3(c), the annual report shall contain the following information, as applicable: (a) The annual quantity of associated storage in metric tons of CO2 (mstored). (b) The density of CO2 if volumetric units are converted to mass in order to be reported for annual quantity of CO2 stored. (c) The annual quantity of CO2 input (minput) and the information in paragraphs (c)(1) and (2) of this section. (1) The annual total mass of CO2 received at the custody transfer meter by the CO2–EOR project, including CO2 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.067</GPH> lotter on DSK11XQN23PROD with RULES2 m1oss operations § 98.482 31949 lotter on DSK11XQN23PROD with RULES2 31950 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations transferred from another CO2–EOR project (mreceived). (2) The annual mass of native CO2 produced and captured in the CO2–EOR project (mnative). (d) The annual mass of CO2 that is recycled and reinjected into the EOR complex. (e) The annual total mass of CO2 loss from project operations (mloss operations), and the information in paragraphs (e)(1) through (4) of this section. (1) Loss of CO2 due to leakage from production, handling, and recycling CO2–EOR facilities (infrastructure including wellheads) (mloss leakage facilities). (2) Loss of CO2 from venting/flaring from production operations (mloss vent/flare). (3) Loss of CO2 due to entrainment within produced gas/oil/water when this CO2 is not separated and reinjected (mloss entrained). (4) Loss of CO2 due to any transfer of CO2 outside the CO2–EOR project (mloss transfer). (f) The total mass of CO2 loss from the EOR complex (mloss EOR complex). (g) Annual documentation that contains the following components as described in Clause 4.4 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7): (1) The formulas used to quantify the annual mass of associated storage, including the mass of CO2 delivered to the CO2–EOR project and losses during the period covered by the documentation (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (2) The methods used to estimate missing data and the amounts estimated as described in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (3) The approach and method for quantification utilized by the operator, including accuracy, precision, and uncertainties (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (4) A statement describing the nature of validation or verification including the date of review, process, findings, and responsible person or entity. (5) Source of each CO2 stream quantified as associated storage (see Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (6) A description of the procedures used to detect and characterize the total CO2 leakage from the EOR complex. (7) If only the mass of anthropogenic CO2 is considered for mstored, a description of the derivation and application of anthropogenic CO2 allocation ratios for all the terms described in Clauses 8.1 to 8.4.6 of CSA/ VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (8) Any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided, including the mass balance calculations as well as information regarding monitoring and containment assurance, is accurate and complete. (h) Any changes made within the reporting year to containment assurance and monitoring approaches and procedures in the EOR operations management plan. § 98.487 Records that must be retained. You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must comply with the record retention requirements in Clause 9.1 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). § 98.488 Plan. EOR Operations Management (a) You must prepare and update, as necessary, a general EOR operations management plan that provides a description of the EOR complex and engineered system (see Clause 4.3(a) of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)), establishes that the EOR complex is adequate to provide safe, long-term containment of CO2, and includes site-specific and other information including: (1) Geologic characterization of the EOR complex. (2) A description of the facilities within the CO2–EOR project. (3) A description of all wells and other engineered features in the CO2– EOR project. (4) The operations history of the project reservoir. (5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (b) You must prepare initial documentation at the beginning of the quantification period, and include the following as described in the EOR operations management plan: (1) A description of the EOR complex and engineered systems (see Clause 5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (2) The initial containment assurance (see Clause 6.1.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (3) The monitoring program (see Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (4) The quantification method to be used (see Clause 8 and Annex B of CSA/ PO 00000 Frm 00150 Fmt 4701 Sfmt 4700 ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (5) The total mass of previously injected CO2 (if any) within the EOR complex at the beginning of the CO2– EOR project (see Clause 8.5 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (c) The EOR operation management plan in paragraph (a) of this section and initial documentation in paragraph (b) of this section must be submitted to the Administrator with the annual report covering the first reporting year that the facility reports under this subpart. In addition, any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided is accurate and complete, must also be provided to the Administrator. (d) If the EOR operations management plan is updated, the updated EOR management plan must be submitted to the Administrator with the annual report covering the first reporting year for which the updated EOR operation management plan is applicable. § 98.489 Definitions. Except as provided in paragraphs (a) and (b) of this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additional terms and definitions are provided in Clause 3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). Subpart WW—Coke Calciners Sec. 98.490 Definition of the source category. 98.491 Reporting threshold. 98.492 GHGs to report. 98.493 Calculating GHG emissions. 98.494 Monitoring and QA/QC requirements. 98.495 Procedures for estimating missing data. 98.496 Data reporting requirements. 98.497 Records that must be retained. 98.498 Definitions. § 98.490 Definition of the source category. (a) A coke calciner is a process unit that heats petroleum coke to high temperatures for the purpose of removing impurities or volatile substances in the petroleum coke feedstock. (b) This source category consists of rotary kilns, rotary hearth furnaces, or similar process units used to calcine petroleum coke and also includes afterburners or other emission control systems used to treat the coke calcining unit’s process exhaust gas. E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations § 98.493 GHGs to report. You must report: (a) CO2, CH4, and N2O emissions from each coke calcining unit under this subpart. (b) CO2, CH4, and N2O emissions from auxiliary fuel used in the coke calcining unit and afterburner, if applicable, or other control system used to treat the coke calcining unit’s process off-gas under subpart C of this part by following the requirements of subpart C. CO2= 44 X L~=1(Minm X CCGcm - (Moutm 12 ' Where: CO2 = Annual CO2 emissions (metric tons CO2/year). m = Month index. Min,m = Mass of green coke fed to the coke calcining unit in month ‘‘m’’ from facility records (metric tons/year). CCGC.m = Mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data in month ‘‘m’’ (metric ton carbon/metric ton green coke). If measurements are made more frequently than monthly, determine the monthly average as the arithmetic average for all measurements made during the calendar month. ' 4 = lotter on DSK11XQN23PROD with RULES2 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 X CCMPcm) ' CCMPC,m = Mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit in month ‘‘m’’ from facility measurement data (metric ton carbon/metric ton petroleum coke). If measurements are made more frequently than monthly, determine the monthly average as the arithmetic average for all measurements made during the calendar month. 44 = Molecular weight of CO2 (kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole). (3) Calculate CH4 emissions using equation 2 to this paragraph (b)(3). Equation 2 to paragraph (b)(3) (co 2 X EmF1 EmFz) EmF1 = Default CO2 emission factor for petroleum coke from table C–1 to subpart C of this part (kg CO2/MMBtu). EmF2 = Default CH4 emission factor for ‘‘Petroleum Products (All fuel types in table C–1)’’ from table C–2 to subpart C of this part (kg CH4/MMBtu). (4) Calculate N2O emissions using equation 3 to this paragraph (b)(4). Equation 3 to paragraph (b)(4) N2 O = Where: N2O = Annual nitrous oxide emissions (metric tons N2O/year). CO2 = Annual CO2 emissions calculated in paragraph (b)(1) or (2) of this section, as applicable (metric tons CO2/year). EmF1 = Default CO2 emission factor for petroleum coke from table C–1 to subpart C of this part (kg CO2/MMBtu). EmF3 = Default N2O emission factor for ‘‘Petroleum Products (All fuel types in table C–1)’’ from table C–2 to subpart C of this part (kg N2O/MMBtu). Equation 1 to paragraph (b)(2) + Mdustm) ' Mout,m = Mass of marketable petroleum coke produced by the coke calcining unit in month ‘‘m’’ from facility records (metric tons petroleum coke/year). Mdust,m = Mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit in month ‘‘m’’ from facility records (metric ton petroleum coke dust/year). For coke calcining units that recycle the collected dust, the mass of coke dust removed from the process is the mass of coke dust collected less the mass of coke dust recycled to the process. CH Where: CH4 = Annual methane emissions (metric tons CH4/year). CO2 = Annual CO2 emissions calculated in paragraph (b)(1) or (2) of this section, as applicable (metric tons CO2/year). ' emissions should be calculated in accordance with subpart C of this part and subtracted from the CO2 CEMS emissions to determine process CO2 emissions. Other coke calcining units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part or follow the requirements of paragraph (b)(2) of this section. (2) Calculate the CO2 emissions from the coke calcining unit using monthly measurements and equation 1 to this paragraph (b)(2). (co 2 X EmF EmF 3) 1 § 98.494 Monitoring and QA/QC requirements. (a) Flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO2 emissions according to subpart C of this part or that are associated with stationary combustion sources must meet the applicable monitoring and QA/QC requirements in § 98.34. PO 00000 Frm 00151 Fmt 4701 Sfmt 4700 (b) Determine the mass of petroleum coke monthly as required by equation 1 to § 98.493(b)(2) using mass measurement equipment meeting the requirements for commercial weighing equipment as described in NIST HB 44– 2023 (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by NIST HB 44–2023 (incorporated by reference, see § 98.7) or the procedures specified by the E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.070</GPH> § 98.492 Calculating GHG emissions. (a) Calculate GHG emissions required to be reported in § 98.492(a) using the applicable methods in paragraph (b) of this section. (b) For each coke calcining unit, calculate GHG emissions according to the applicable provisions in paragraphs (b)(1) through (4) of this section. (1) If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part, you must calculate and report CO2 emissions under this subpart by following the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. Auxiliary fuel use CO2 ER25AP24.069</GPH> Reporting threshold. You must report GHG emissions under this subpart if your facility contains a coke calciner and the facility meets the requirements of either § 98.2(a)(1) or (2). ER25AP24.068</GPH> § 98.491 31951 31952 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer. (c) Determine the carbon content of petroleum coke as required by equation 1 § 98.493(b)(2) using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer. (1) ASTM D3176–15 (incorporated by reference, see § 98.7). (2) ASTM D5291–16 (incorporated by reference, see § 98.7). (3) ASTM D5373–21 (incorporated by reference, see § 98.7). (d) The owner or operator must document the procedures used to ensure the accuracy of the monitoring systems used including but not limited to calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded. § 98.495 Procedures for estimating missing data. lotter on DSK11XQN23PROD with RULES2 A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter must be used in the calculations. (a) For missing auxiliary fuel use data, use the missing data procedures in subpart C of this part. (b) For each missing value of mass or carbon content of coke, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ‘‘after’’ value is not obtained by the end of the reporting year, you may use the ‘‘before’’ value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. (c) For missing CEMS data, you must use the missing data procedures in § 98.35. § 98.496 Data reporting requirements. In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (i) of this section for each coke calcining unit. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (a) The unit ID number (if applicable). (b) Maximum rated throughput of the unit, in metric tons coke calcined/ stream day. (c) The calculated CO2, CH4, and N2O annual process emissions, expressed in metric tons of each pollutant emitted. (d) A description of the method used to calculate the CO2 emissions for each unit (e.g., CEMS or equation 1 to § 98.493(b)(2)). (e) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year). (f) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year). (g) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records (metric tons/year) and an indication of whether coke dust is recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled). (h) Annual average mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke). (i) Annual average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke). § 98.497 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section. (a) The records of all parameters monitored under § 98.494. (b) The applicable verification software records as identified in this paragraph (b). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (b)(1) through (5) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (5) of this section. (1) Monthly mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (2) Monthly mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (3) Monthly mass of petroleum coke dust removed from the process through the dust collection system of the coke PO 00000 Frm 00152 Fmt 4701 Sfmt 4700 calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (4) Average monthly mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke) (equation 1 to § 98.493(b)(2)). (5) Average monthly mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke) (equation 1 to § 98.493(b)(2)). § 98.498 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart XX—Calcium Carbide Production Sec. 98.500 Definition of the source category. 98.501 Reporting threshold. 98.502 GHGs to report. 98.503 Calculating GHG emissions. 98.504 Monitoring and QA/QC requirements. 98.505 Procedures for estimating missing data. 98.506 Data reporting requirements. 98.507 Records that must be retained. 98.508 Definitions. § 98.500 Definition of the source category. The calcium carbide production source category consists of any facility that produces calcium carbide. § 98.501 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a calcium carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.502 GHGs to report. You must report: (a) Process CO2 emissions from each calcium carbide process unit or furnace used for the production of calcium carbide. (b) CO2, CH4, and N2O emissions from each stationary combustion unit following the requirements of subpart C of this part. You must report these emissions under subpart C of this part by following the requirements of subpart C. § 98.503 Calculating GHG emissions. You must calculate and report the annual process CO2 emissions from each calcium carbide process unit not subject to paragraph (c) of this section using the procedures in either paragraph (a) or (b) of this section. (a) Calculate and report under this subpart the combined process and E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations combustion CO2 emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. (b) Calculate and report under this subpart the annual process CO2 emissions from the calcium carbide process unit using the carbon mass Eco2 = balance procedure specified in paragraphs (b)(1) and (2) of this section. (1) For each calcium carbide process unit, determine the annual mass of carbon in each carbon-containing input and output material for the calcium carbide process unit and estimate annual process CO2 emissions from the calcium carbide process unit using equation 1 to this paragraph (b)(1). 44 2000 "'i (M reducing agenti X 12 X 2205 X L..1 44 + 12 X 31953 Carbon-containing input materials include carbon electrodes and carbonaceous reducing agents. If you document that a specific input or output material contributes less than 1 percent of the total carbon into or out of the process, you do not have to include the material in your calculation using equation 1. Equation 1 to paragraph (b)(1) Creducing agenti ) 2000 me ) 2205 X L1 Melectrodem X Celectrodem 44 2000 k( ) - 12 X 2205 X L1 Mproduct outgoingk X Cproduct outgoingk 44 2000 I( ) - 12 X 2205 X L1 Mnon-product outgoing1 X Cnon-product outgoing1 lotter on DSK11XQN23PROD with RULES2 (2) Determine the combined annual process CO2 emissions from the calcium carbide process units at your facility using equation 2 to this paragraph (b)(2). Equation 2 to paragraph (b)(2) CO2 = S1k ECO2k Where: CO2 = Annual process CO2 emissions from calcium carbide process units at a VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 facility used for the production of calcium carbide (metric tons). ECO2k = Annual process CO2 emissions calculated from calcium carbide process unit k calculated using equation 1 to paragraph (b)(1) of this section (metric tons). k = Total number of calcium carbide process units at facility. (c) If all GHG emissions from a calcium carbide process unit are vented through the same stack as any combustion unit or process equipment that reports CO2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, then the calculation methodology in paragraph (b) of this section must not be used to calculate process emissions. The owner or operator must report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. § 98.504 Monitoring and QA/QC requirements. If you determine annual process CO2 emissions using the carbon mass balance procedure in § 98.503(b), you must meet the requirements specified in paragraphs (a) and (b) of this section. (a) Determine the annual mass for each material used for the calculations of annual process CO2 emissions using equation 1 to § 98.503(b)(1) by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments PO 00000 Frm 00153 Fmt 4701 Sfmt 4700 used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating information. (b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output. (1) Information provided by your material supplier. (2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) and (ii) of this section, as applicable. (i) ASTM D5373–08 (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes. (ii) ASTM C25–06 (incorporated by reference, see § 98.7) for analysis of materials such as limestone or dolomite. § 98.505 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.071</GPH> Where: ECO2 = Annual process CO2 emissions from an individual calcium carbide process unit (metric tons). 44/12 = Ratio of molecular weights, CO2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. Mreducing agenti = Annual mass of reducing agent i fed, charged, or otherwise introduced into the calcium carbide process unit (tons). Creducing agenti = Carbon content in reducing agent i (percent by weight, expressed as a decimal fraction). Melectrodem = Annual mass of carbon electrode m consumed in the calcium carbide process unit (tons). Celectrodem = Carbon content of the carbon electrode m (percent by weight, expressed as a decimal fraction). Mproduct outgoingk = Annual mass of alloy product k tapped from the calcium carbide process unit (tons). Cproduct outgoingk = Carbon content in alloy product k (percent by weight, expressed as a decimal fraction). Mnon-product outgoingl = Annual mass of nonproduct outgoing material l removed from the calcium carbide unit (tons). Cnon-product outgoing = Carbon content in nonproduct outgoing material l (percent by weight, expressed as a decimal fraction). 31954 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations calculations in § 98.503 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) If you determine CO2 emissions for the calcium carbide process unit at your facility using the carbon mass balance procedure in § 98.503(b), 100 percent data availability is required for the carbon content of the input and output materials. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.504(b) if data are missing. (b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must be based on the best available estimate of the mass of the inputs and outputs from all available process data or data used for accounting purposes, such as purchase records. lotter on DSK11XQN23PROD with RULES2 § 98.506 § 98.507 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (h) of this section, as applicable: (a) Annual facility calcium carbide production capacity (tons). (b) The annual facility production of calcium carbide (tons). (c) Total number of calcium carbide process units at facility used for production of calcium carbide. (d) Annual facility consumption of petroleum coke (tons). (e) Each end use of any calcium carbide produced and sent off site. (f) If the facility produces acetylene on site, provide the information in paragraphs (f)(1) through (3) of this section. (1) The annual production of acetylene at the facility (tons). (2) The annual quantity of calcium carbide used for the production of acetylene at the facility (tons). (3) Each end use of any acetylene produced on-site. (g) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required by § 98.36 for the Tier 4 Calculation Methodology and the information specified in paragraphs (g)(1) and (2) of this section. (1) Annual CO2 emissions (in metric tons) from each CEMS monitoring location measuring process emissions from the calcium carbide process unit. (2) Identification number of each process unit. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (h) If a CEMS is not used to measure CO2 process emissions, and the carbon mass balance procedure is used to determine CO2 emissions according to the requirements in § 98.503(b), then you must report the information specified in paragraphs (h)(1) through (3) of this section. (1) Annual process CO2 emissions (in metric tons) from each calcium carbide process unit. (2) List the method used for the determination of carbon content for each input and output material included in the calculation of annual process CO2 emissions for each calcium carbide process unit (i.e., supplier provided information, analyses of representative samples you collected). (3) If you use the missing data procedures in § 98.505(b), you must report for each calcium carbide production process unit how monthly mass of carbon-containing inputs and outputs with missing data were determined and the number of months the missing data procedures were used. Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each calcium carbide process unit, as applicable. (a) If a CEMS is used to measure CO2 emissions according to the requirements in § 98.503(a), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37 and the information specified in paragraphs (a)(1) through (3) of this section. (1) Monthly calcium carbide process unit production quantity (tons). (2) Number of calcium carbide processing unit operating hours each month. (3) Number of calcium carbide processing unit operating hours in a calendar year. (b) If the carbon mass balance procedure is used to determine CO2 emissions according to the requirements in § 98.503(b)(2), then you must retain records for the information specified in paragraphs (b)(1) through (5) of this section. (1) Monthly calcium carbide process unit production quantity (tons). (2) Number of calcium carbide process unit operating hours each month. (3) Number of calcium carbide process unit operating hours in a calendar year. (4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO2 emissions (tons). PO 00000 Frm 00154 Fmt 4701 Sfmt 4700 (5) Average carbon content determined and records of the supplier provided information or analyses used for the determination for each material included for the calculations of annual process CO2 emissions. (c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each calcium carbide process unit, including documentation of specific input or output materials excluded from equation 1 to § 98.503(b)(1) that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in a calcium carbide process unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (8) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (8) of this section. (1) Carbon content in reducing agent (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (2) Annual mass of reducing agent fed, charged, or otherwise introduced into the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (3) Carbon content of carbon electrode (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (4) Annual mass of carbon electrode consumed in the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (5) Carbon content in product (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (6) Annual mass of product produced/ tapped in the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (7) Carbon content in non-product outgoing material (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (8) Annual mass of non-product outgoing material removed from calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). E:\FR\FM\25APR2.SGM 25APR2 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart YY—Caprolactam, Glyoxal, and Glyoxylic Acid Production Sec. 98.510 Definition of the source category. 98.511 Reporting threshold. 98.512 GHGs to report. 98.513 Calculating GHG emissions. 98.514 Monitoring and QA/QC requirements. 98.515 Procedures for estimating missing data. 98.516 Data reporting requirements. 98.517 Records that must be retained. 98.518 Definitions. Table 1 to Subpart YY of Part 98—N2O Generation Factors § 98.512 GHGs to report. (a) You must report N2O process emissions from the production of caprolactam, glyoxal, and glyoxylic acid as required by this subpart. (b) You must report under subpart C of this part the emissions of CO2, CH4, and N2O from each stationary combustion unit by following the requirements of subpart C of this part. § 98.513 Calculating GHG emissions. each N2O abatement technology according to paragraph (c)(1) or (2) of this section. (1) Use the control device manufacturer’s specified destruction efficiency. (2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency. (d) If process line t exhausts to any N2O abatement technology j, you must determine the abatement utilization factor for each N2O abatement technology according to paragraph (d)(1) or (2) of this section. (1) If the abatement technology j has no downtime during the year, use 1. (2) If the abatement technology j was not operational while product i was being produced on process line t, calculate the abatement utilization factor according to equation 1 to this paragraph (d)(2). You must report GHG emissions under this subpart if your facility meets (a) You must determine annual N2O process emissions from each caprolactam, glyoxal, and glyoxylic acid process line using the appropriate default N2O generation factor(s) from table 1 to this subpart, the site-specific N2O destruction factor(s) for each N2O abatement device, and site-specific production data according to paragraphs (b) through (e) of this section. (b) You must determine the total annual amount of product i (caprolactam, glyoxal, or glyoxylic acid) produced on each process line t (metric tons product), according to § 98.514(b). (c) If process line t exhausts to any N2O abatement technology j, you must determine the destruction efficiency for Where: AFj = Monthly abatement utilization factor of N2O abatement technology j from process unit t (fraction of time that abatement technology is operating). Ti,j = Total number of hours during month that product i (caprolactam, glyoxal, or glyoxylic acid), was produced from process unit t during which N2O abatement technology j was operational (hours). Ti = Total number of hours during month that product i (caprolactam, glyoxal, or glyoxylic acid), was produced from process unit t (hours). (e) You must calculate N2O emissions for each product i from each process line t and each N2O control technology j according to equation 2 to this paragraph (e). Where: EN2Ot = Monthly process emissions of N2O, metric tons from process line t. EFi = N2O generation factor for product i (caprolactam, glyoxal, or glyoxylic acid), kg N2O/metric ton of product produced, as shown in table 1 to this subpart. Pi = Monthly production of product i, (caprolactam, glyoxal, or glyoxylic acid), metric tons. DEj = Destruction efficiency of N2O abatement technology type j, fraction (decimal fraction of N2O removed from vent stream). AFj = Monthly abatement utilization factor for N2O abatement technology type j, fraction, calculated using equation 1 to paragraph (d)(2) of this section. 0.001 = Conversion factor from kg to metric tons. (f) You must determine the annual emissions combined from each process line at your facility using equation 3 to this paragraph (f): Definition of the source category. This source category includes any facility that produces caprolactam, glyoxal, or glyoxylic acid. This source category excludes the production of glyoxal through the LaPorte process (i.e., the gas-phase catalytic oxidation of ethylene glycol with air in the presence of a silver or copper catalyst). § 98.511 Reporting threshold. Equation 1 to paragraph (d)(2) Equation 2 to paragraph (e) Equation 3 to paragraph (f) ER25AP24.074</GPH> § 98.510 12 N2 0 = ER25AP24.073</GPH> lotter on DSK11XQN23PROD with RULES2 the requirements of either § 98.2(a)(1) or (2) and the definition of source category in § 98.510. L EN2ot 1 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00155 Fmt 4701 Sfmt 4725 E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.072</GPH> § 98.508 31955 31956 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Where: N2O = Annual process N2O emissions from each process line for product i (caprolactam, glyoxal, or glyoxylic acid) (metric tons). EN2Ot = Monthly process emissions of N2O from each process line for product i (caprolactam, glyoxal, or glyoxylic acid) (metric tons). § 98.514 Monitoring and QA/QC requirements. (a) You must determine the total monthly amount of caprolactam, glyoxal, and glyoxylic acid produced. These monthly amounts are determined according to the methods in paragraph (a)(1) or (2) of this section. (1) Direct measurement of production (such as using flow meters, weigh scales, etc.). (2) Existing plant procedures used for accounting purposes (i.e., dedicated tank-level and acid concentration measurements). (b) You must determine the annual amount of caprolactam, glyoxal, and glyoxylic acid produced. These annual amounts are determined by summing the respective monthly quantities determined in paragraph (a) of this section. § 98.515 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of caprolactam, glyoxal, or glyoxylic acid production, the substitute data must be the best available estimate based on all available process data or data used for accounting purposes (such as sales records). (b) For missing values related to the N2O abatement device, assuming that the operation is generally constant from year to year, the substitute data value should be the most recent qualityassured value. lotter on DSK11XQN23PROD with RULES2 § 98.516 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (j) of this section. (a) Process line identification number. (b) Annual process N2O emissions from each process line according to paragraphs (b)(1) through (3) of this section. (1) N2O from caprolactam production (metric tons). VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 (2) N2O from glyoxal production (metric tons). (3) N2O from glyoxylic acid production (metric tons). (c) Annual production quantities from all process lines at the caprolactam, glyoxal, or glyoxylic acid production facility according to paragraphs (c)(1) through (3) of this section. (1) Caprolactam production (metric tons). (2) Glyoxal production (metric tons). (3) Glyoxylic acid production (metric tons). (d) Annual production capacity from all process lines at the caprolactam, glyoxal, or glyoxylic acid production facility, as applicable, in paragraphs (d)(1) through (3) of this section. (1) Caprolactam production capacity (metric tons). (2) Glyoxal production capacity (metric tons). (3) Glyoxylic acid production capacity (metric tons). (e) Number of process lines at the caprolactam, glyoxal, or glyoxylic acid production facility, by product, in paragraphs (e)(1) through (3) of this section. (1) Total number of process lines producing caprolactam. (2) Total number of process lines producing glyoxal. (3) Total number of process lines producing glyoxylic acid. (f) Number of operating hours in the calendar year for each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (hours). (g) N2O abatement technologies used (if applicable) and date of installation of abatement technology at the caprolactam, glyoxal, or glyoxylic acid production facility. (h) Monthly abatement utilization factor for each N2O abatement technology for each process line at the caprolactam, glyoxal, or glyoxylic acid production facility. (i) Number of times in the reporting year that missing data procedures were followed to measure production quantities of caprolactam, glyoxal, or glyoxylic acid (months). (j) Annual percent N2O emission reduction per chemical produced at the caprolactam, glyoxal, or glyoxylic acid production facility, as applicable, in paragraphs (j)(1) through (3) of this section. (1) Annual percent N2O emission reduction for all caprolactam production process lines. (2) Annual percent N2O emission reduction for all glyoxal production process lines. (3) Annual percent N2O emission reduction for all glyoxylic acid production process lines. PO 00000 Frm 00156 Fmt 4701 Sfmt 4700 § 98.517 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each caprolactam, glyoxal, or glyoxylic acid production facility: (a) Documentation of how accounting procedures were used to estimate production rate. (b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable). (c) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (4) of this section. (1) Monthly production quantity of caprolactam from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (2) Monthly production quantity of glyoxal from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (3) Monthly production quantity of glyoxylic acid from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (4) Destruction efficiency of N2O abatement technology from each process line, fraction (decimal fraction of N2O removed from vent stream). § 98.518 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. TABLE 1 TO SUBPART YY OF PART 98—N2O GENERATION FACTORS Product Caprolactam ............................. Glyoxal ...................................... E:\FR\FM\25APR2.SGM 25APR2 N2O generation factor a 9.0 520 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations Product N2O generation factor a Glyoxylic acid ............................ a Generation N2O emitted produced. 100 factors in units of kilograms of per metric ton of product Subpart ZZ—Ceramics Manufacturing Sec. 98.520 Definition of the source category. 98.521 Reporting threshold. 98.522 GHGs to report. 98.523 Calculating GHG emissions. 98.524 Monitoring and QA/QC requirements. 98.525 Procedures for estimating missing data. 98.526 Data reporting requirements. 98.527 Records that must be retained. 98.528 Definitions. Table 1 to Subpart ZZ of Part 98—CO2 Emission Factors for Carbonate-Based Raw Materials § 98.520 Definition of the source category. lotter on DSK11XQN23PROD with RULES2 (a) The ceramics manufacturing source category consists of any facility that uses nonmetallic, inorganic materials, many of which are claybased, to produce ceramic products such as bricks and roof tiles, wall and floor tiles, table and ornamental ware (household ceramics), sanitary ware, refractory products, vitrified clay pipes, expanded clay products, inorganic bonded abrasives, and technical ceramics (e.g., aerospace, automotive, electronic, or biomedical applications). For the purposes of this subpart, ceramics manufacturing processes include facilities that annually consume Where: ECO2 = Annual process CO2 emissions (metric tons/year). Mj = Annual mass of the carbonate-based raw material j consumed (tons/year). 2000/2205 = Conversion factor to convert tons to metric tons. MFi = Annual average decimal mass fraction of carbonate-based mineral i in carbonate-based raw material j. EFi = Emission factor for the carbonate-based mineral i, (metric tons CO2/metric ton carbonate, see table 1 to this subpart). Fi = Decimal fraction of calcination achieved for carbonate-based mineral i, assumed to be equal to 1.0. i = Index for carbonate-based mineral in each carbonate-based raw material. j = Index for carbonate-based raw material. VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 sufficient to allow the calcination reaction to occur, and operate a ceramics manufacturing process unit. (b) A ceramics manufacturing process unit is a kiln, dryer, or oven used to calcine clay or other carbonate-based materials for the production of a ceramics product. § 98.521 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a ceramics manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.522 GHGs to report. You must report: (a) CO2 process emissions from each ceramics process unit (e.g., kiln, dryer, or oven). (b) CO2 combustion emissions from each ceramics process unit. (c) CH4 and N2O combustion emissions from each ceramics process unit. You must calculate and report these emissions under subpart C of this part by following the requirements of subpart C of this part. (d) CO2, CH4, and N2O combustion emissions from each stationary fuel combustion unit other than kilns, dryers, or ovens. You must report these emissions under subpart C of this part by following the requirements of subpart C of this part. § 98.523 Calculating GHG emissions. You must calculate and report the annual process CO2 emissions from each ceramics process unit using the procedures in paragraphs (a) through (c) of this section. (5) Determine the combined annual process CO2 emissions from the ceramic process units at your facility using equation 2 to this paragraph (b)(5): Equation 2 to paragraph (b)(5) CO2 = Sk1 ECO2k Where: CO2 = Annual process CO2 emissions from ceramic process units at a facility (metric tons). ECO2k = Annual process CO2 emissions calculated from ceramic process unit k calculated using equation 1 to paragraph (b)(4) of this section (metric tons). k = Total number of ceramic process units at facility. PO 00000 Frm 00157 Fmt 4701 Sfmt 4700 (a) For each ceramics process unit that meets the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO2 emissions by operating and maintaining a CEMS to measure CO2 emissions according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part. (b) For each ceramics process unit that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2 emissions from the ceramics process unit separately by using the procedures specified in paragraphs (b)(1) through (6) of this section, except as specified in paragraph (c) of this section. (1) For each carbonate-based raw material (including clay) charged to the ceramics process unit, either obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, or use a default value of 1.0 as the mass fraction for the raw material. (2) Determine the quantity of each carbonate-based raw material charged to the ceramics process unit. (3) Apply the appropriate emission factor for each carbonate-based raw material charged to the ceramics process unit. Table 1 to this subpart provides emission factors based on stoichiometric ratios for carbonate-based minerals. (4) Use equation 1 to this paragraph (b)(4) to calculate process mass emissions of CO2 for each ceramics process unit: Equation 1 to paragraph (b)(4) (6) Calculate and report under subpart C of this part the combustion CO2 emissions in the ceramics process unit according to the applicable requirements in subpart C of this part. (c) A value of 1.0 can be used for the mass fraction (MFi) of carbonate-based mineral i in each carbonate-based raw material j in equation 1 to paragraph (b)(4) of this section. The use of 1.0 for the mass fraction assumes that the carbonate-based raw material comprises 100% of one carbonate-based mineral. As an alternative to the default value, you may use data provided by either the raw material supplier or a lab analysis. E:\FR\FM\25APR2.SGM 25APR2 ER25AP24.075</GPH> at least 2,000 tons of carbonates, either TABLE 1 TO SUBPART YY OF PART 98—N2O GENERATION FACTORS— as raw materials or as a constituent in clay, which is heated to a temperature Continued 31957 31958 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations lotter on DSK11XQN23PROD with RULES2 § 98.524 Monitoring and QA/QC requirements. (a) You must measure annual amounts of carbonate-based raw materials charged to each ceramics process unit from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to ceramics process units at the facility must be compared to records of raw material purchases for the year. (b) You must use the default value of 1.0 for the mass fraction of a carbonatebased mineral, or you may opt to obtain the mass fraction of any carbonate-based materials from the supplier of the raw material or by sampling the raw material. If you opt to obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, you must measure the carbonate-based mineral mass fractions at least annually to verify the mass fraction data. You may conduct the sampling and chemical analysis using any x-ray fluorescence test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API). If it is determined that the mass fraction of a carbonate based raw material is below the detection limit of available industry testing standards, you may use a default value of 0.005. (c) You must use the default value of 1.0 for the mass fraction of a carbonatebased mineral, or you may opt to obtain the mass fraction of any carbonate-based materials from the supplier of the raw material or by sampling the raw material. If you obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material at least annually by calculating an arithmetic average of the data obtained from raw material suppliers or sampling and chemical analysis. (d) You must use the default value of 1.0 for the calcination fraction of a carbonate-based mineral. Alternatively, you may opt to obtain the calcination fraction of any carbonate-based mineral by sampling. If you opt to obtain the calcination fraction of any carbonatebased minerals from sampling, you must determine on an annual basis the calcination fraction for each carbonatebased mineral consumed based on sampling and chemical analysis. You may conduct the sampling and chemical analysis using any x-ray fluorescence VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API). § 98.525 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in § 98.523 is required. If the monitoring and quality assurance procedures in § 98.524 cannot be followed and data is unavailable, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section in the calculations. You must document and keep records of the procedures used for all such missing value estimates. (a) If the CEMS approach is used to determine combined process and combustion CO2 emissions, the missing data procedures in § 98.35 apply. (b) For missing data on the monthly amounts of carbonate-based raw materials charged to any ceramics process unit, use the best available estimate(s) of the parameter(s) based on all available process data or data used for accounting purposes, such as purchase records. (c) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials, assume that the mass fraction of a carbonate-based mineral is 1.0, which assumes that one carbonate-based mineral comprises 100 percent of the carbonate-based raw material. § 98.526 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (c) of this section, as applicable: (a) The total number of ceramics process units at the facility and the number of units that operated during the reporting year. (b) If a CEMS is used to measure CO2 emissions from ceramics process units, then you must report under this subpart the relevant information required under § 98.36 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (b)(1) through (3) of this section. (1) The annual quantity of each carbonate-based raw material (including clay) charged to each ceramics process unit and for all units combined (tons). (2) Annual quantity of each type of ceramics product manufactured by each ceramics process unit and by all units combined (tons). (3) Annual production capacity for each ceramics process unit (tons). (c) If a CEMS is not used to measure CO2 emissions from ceramics process PO 00000 Frm 00158 Fmt 4701 Sfmt 4700 units and process CO2 emissions are calculated according to the procedures specified in § 98.523(b), then you must report the following information specified in paragraphs (c)(1) through (7) of this section. (1) Annual process emissions of CO2 (metric tons) for each ceramics process unit and for all units combined. (2) The annual quantity of each carbonate-based raw material (including clay) charged to each ceramics process unit and for all units combined (tons). (3) Results of all tests used to verify each carbonate-based mineral mass fraction for each carbonate-based raw material charged to a ceramics process unit, as specified in paragraphs (c)(3)(i) through (iii) of this section. (i) Date of test. (ii) Method(s) and any variations used in the analyses. (iii) Mass fraction of each sample analyzed. (4) Method used to determine the decimal mass fraction of carbonatebased mineral, unless you used the default value of 1.0 (e.g., supplier provided information, analyses of representative samples you collected, or use of a default value of 0.005 as specified by § 98.524(b)). (5) Annual quantity of each type of ceramics product manufactured by each ceramics process unit and by all units combined (tons). (6) Annual production capacity for each ceramics process unit (tons). (7) If you use the missing data procedures in § 98.525(b), you must report for each applicable ceramics process unit the number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials or mass fraction of the carbonate-based minerals (months). § 98.527 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each ceramics process unit, as applicable. (a) If a CEMS is used to measure CO2 emissions according to the requirements in § 98.523(a), then you must retain under this subpart the records required under § 98.37 for the Tier 4 Calculation Methodology and the information specified in paragraphs (a)(1) and (2) of this section. (1) Monthly ceramics production rate for each ceramics process unit (tons). (2) Monthly amount of each carbonate-based raw material charged to each ceramics process unit (tons). (b) If process CO2 emissions are calculated according to the procedures E:\FR\FM\25APR2.SGM 25APR2 31959 Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules and Regulations specified in § 98.523(b), you must retain the records in paragraphs (b)(1) through (6) of this section. (1) Monthly ceramics production rate for each ceramics process unit (metric tons). (2) Monthly amount of each carbonate-based raw material charged to each ceramics process unit (metric tons). (3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in equation 1 to § 98.523(b)(4), if applicable. (4) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a ceramics process unit, including the data specified in paragraphs (b)(4)(i) through (v) of this section. (i) Date of test. (ii) Method(s), and any variations of methods, used in the analyses. (iii) Mass fraction of each sample analyzed. (iv) Relevant calibration data for the instrument(s) used in the analyses. (v) Name and address of laboratory that conducted the tests. (5) Each carbonate-based mineral mass fraction for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO2. (6) Number of annual operating hours of each ceramics process unit. (c) All other documentation used to support the reported GHG emissions. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (3) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (3) of this section. (1) Annual average decimal mass fraction of each carbonate-based mineral in each carbonate-based raw material for each ceramics process unit (specify the default value, if used, or the value determined according to § 98.524) (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.523(b)(4)). (2) Annual mass of each carbonatebased raw material charged to each ceramics process unit (tons) (equation 1 to § 98.523(b)(4)). (3) Decimal fraction of calcination achieved for each carbonate-based raw material for each ceramics process unit (specify the default value, if used, or the value determined according to § 98.524) (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.523(b)(4)). § 98.528 Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. TABLE 1 TO SUBPART ZZ OF PART 98—CO2 EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS CO2 emission factor a Carbonate Mineral name(s) BaCO3 ....................................................... CaCO3 ....................................................... Ca(Fe,Mg,Mn)(CO3)2 ................................ CaMg(CO3)2 .............................................. FeCO3 ....................................................... K2CO3 ....................................................... Li2CO3 ....................................................... MgCO3 ...................................................... MnCO3 ...................................................... Na2CO3 ..................................................... SrCO3 ........................................................ Witherite, Barium carbonate ........................................................................................ Limestone, Calcium Carbonate, Calcite, Aragonite ..................................................... Ankerite b ...................................................................................................................... Dolomite ....................................................................................................................... Siderite ......................................................................................................................... Potassium carbonate ................................................................................................... Lithium carbonate ......................................................................................................... Magnesite ..................................................................................................................... Rhodochrosite .............................................................................................................. Sodium carbonate, Soda ash ...................................................................................... Strontium carbonate, Strontianite ................................................................................ a Emission b Ankerite factors are in units of metric tons of CO2 emitted per metric ton of carbonate-based material. emission factors are based on a formula weight range that assumes Fe, Mg, and Mn are present in amounts of at least 1.0 percent. [FR Doc. 2024–07413 Filed 4–24–24; 8:45 am] BILLING CODE 6560–50–P lotter on DSK11XQN23PROD with RULES2 0.223 0.440 0.408–0.476 0.477 0.380 0.318 0.596 0.522 0.383 0.415 0.298 VerDate Sep<11>2014 19:27 Apr 24, 2024 Jkt 262001 PO 00000 Frm 00159 Fmt 4701 Sfmt 9990 E:\FR\FM\25APR2.SGM 25APR2

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 89, Number 81 (Thursday, April 25, 2024)]
[Rules and Regulations]
[Pages 31802-31959]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-07413]



[[Page 31801]]

Vol. 89

Thursday,

No. 81

April 25, 2024

Part II





Environmental Protection Agency





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40 CFR Parts 9 and 98





Revisions and Confidentiality Determinations for Data Elements Under 
the Greenhouse Gas Reporting Rule; Final Rule

Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules 
and Regulations

[[Page 31802]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 9 and 98

[EPA-HQ-OAR-2019-0424; FRL-7230-01-OAR]
RIN 2060-AU35


Revisions and Confidentiality Determinations for Data Elements 
Under the Greenhouse Gas Reporting Rule

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

SUMMARY: The EPA is amending specific provisions in the Greenhouse Gas 
Reporting Rule to improve data quality and consistency. This action 
updates the General Provisions to reflect revised global warming 
potentials; expands reporting to additional sectors; improves the 
calculation, recordkeeping, and reporting requirements by updating 
existing methodologies; improves data verifications; and provides for 
collection of additional data to better inform and be relevant to a 
wide variety of Clean Air Act provisions that the EPA carries out. This 
action adds greenhouse gas monitoring and reporting for five source 
categories including coke calcining; ceramics manufacturing; calcium 
carbide production; caprolactam, glyoxal, and glyoxylic acid 
production; and facilities conducting geologic sequestration of carbon 
dioxide with enhanced oil recovery. These revisions also include 
changes that will improve implementation of the rule such as updates to 
applicability estimation methodologies, simplifying calculation and 
monitoring methodologies, streamlining recordkeeping and reporting, and 
other minor technical corrections or clarifications. This action also 
establishes and amends confidentiality determinations for the reporting 
of certain data elements to be added or substantially revised in these 
amendments.

DATES: This rule is effective January 1, 2025. The incorporation by 
reference of certain material listed in this final rule is approved by 
the Director of the Federal Register beginning January 1, 2025. The 
incorporation by reference of certain other material listed in the rule 
was approved by the Director of the Federal Register as of January 1, 
2018.

ADDRESSES: The EPA has established a docket for this action under 
Docket ID No. EPA-HQ-OAR-2019-0424. All documents in the docket are 
listed in the www.regulations.gov index. Although listed in the index, 
some information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the internet and will be publicly available only in hard 
copy. Publicly available docket materials are available either 
electronically in www.regulations.gov or in hard copy at the EPA Docket 
Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW, 
Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding legal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744 and the telephone 
number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change 
Division, Office of Atmospheric Programs (MC-6207A), Environmental 
Protection Agency, 1200 Pennsylvania Ave., NW, Washington, DC 20460; 
telephone number: (202) 343-9548; email address: [email protected]. 
For technical information, please go to the Greenhouse Gas Reporting 
Program (GHGRP) website, www.epa.gov/ghgreporting. To submit a 
question, select Help Center, followed by ``Contact Us.''
    World Wide Web (WWW). In addition to being available in the docket, 
an electronic copy of this final rule will also be available through 
the WWW. Following the Administrator's signature, a copy of this final 
rule will be posted on the EPA's GHGRP website at www.epa.gov/ghgreporting.

SUPPLEMENTARY INFORMATION: 
    Regulated entities. These final revisions affect certain entities 
that must submit annual greenhouse gas (GHG) reports under the GHGRP 
(codified at 40 CFR part 98). These are amendments to existing 
regulations and will affect owners or operators of certain industry 
sectors that are suppliers and direct emitters of GHGs. Regulated 
categories and entities include, but are not limited to, those listed 
in table 1 of this preamble:

           Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
                                  North American        Examples of
                                     Industry       facilities that may
           Category               Classification     be subject to part
                                  System (NAICS)            98:+
------------------------------------------------------------------------
General Stationary Fuel         .................  Facilities operating
 Combustion Sources.                          211   boilers, process
                                                    heaters,
                                                    incinerators,
                                                    turbines, and
                                                    internal combustion
                                                    engines.
                                                   Extractors of crude
                                                    petroleum and
                                                    natural gas.
                                              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.
Electric Power Generation.....               2211  Generation facilities
                                                    that produce
                                                    electric energy.
Adipic Acid Production........             325199  All other basic
                                                    organic chemical
                                                    manufacturing:
                                                    Adipic acid
                                                    manufacturing.
Aluminum Production...........             331313  Primary aluminum
                                                    production
                                                    facilities.
Ammonia Manufacturing.........             325311  Anhydrous ammonia
                                                    manufacturing
                                                    facilities.
Calcium Carbide Production....             325180  Other basic inorganic
                                                    chemical
                                                    manufacturing:
                                                    calcium carbide
                                                    manufacturing.

[[Page 31803]]

 
Carbon Dioxide Enhanced Oil                211120  Oil and gas
 Recovery Projects.                                 extraction projects
                                                    using carbon dioxide
                                                    enhanced oil
                                                    recovery.
Caprolactam, Glyoxal, and                  325199  All other basic
 Glyoxylic Acid Production.                         organic chemical
                                                    manufacturing.
Cement Production.............             327310  Cement manufacturing.
Ceramics Manufacturing........             327110  Pottery, ceramics,
                                           327120   and plumbing fixture
                                                    manufacturing.
                                                   Clay building
                                                    material and
                                                    refractories
                                                    manufacturing.
Coke Calcining................             299901  Coke; coke,
                                                    petroleum; coke,
                                                    calcined petroleum.
Electronics Manufacturing.....             334111  Microcomputers
                                                    manufacturing
                                                    facilities.
                                           334413  Semiconductor,
                                                    photovoltaic (PV)
                                                    (solid-state) device
                                                    manufacturing
                                                    facilities.
                                           334419  Liquid crystal
                                                    display (LCD) unit
                                                    screens
                                                    manufacturing
                                                    facilities;
                                                    Microelectromechanic
                                                    al (MEMS)
                                                    manufacturing
                                                    facilities.
Electrical Equipment                        33531  Power transmission
 Manufacture or Refurbishment.                      and distribution
                                                    switchgear and
                                                    specialty
                                                    transformers
                                                    manufacturing
                                                    facilities.
Electricity generation units               221112  Electric power
 that report through 40 CFR                         generation, fossil
 part 75.                                           fuel (e.g., coal,
                                                    oil, gas).
Electrical Equipment Use......             221121  Electric bulk power
                                                    transmission and
                                                    control facilities.
Electrical transmission and                 33361  Engine, Turbine, and
 distribution equipment                             Power Transmission
 manufacture or refurbishment.                      Equipment
                                                    Manufacturing.
Ferroalloy Production.........             331110  Ferroalloys
                                                    manufacturing.
Fluorinated Greenhouse Gas                 325120  Industrial gases
 Production.                                        manufacturing
                                                    facilities.
Geologic Sequestration........                 NA  CO2 geologic
                                                    sequestration sites.
Glass Production..............             327211  Flat glass
                                           327213   manufacturing
                                                    facilities.
                                                   Glass container
                                                    manufacturing
                                                    facilities.
                                           327212  Other pressed and
                                                    blown glass and
                                                    glassware
                                                    manufacturing
                                                    facilities.
HCFC-22 Production............             325120  Industrial gas
                                                    manufacturing:
                                                    Hydrochlorofluorocar
                                                    bon (HCFC) gases
                                                    manufacturing.
HFC-23 destruction processes               325120  Industrial gas
 that are not collocated with                       manufacturing:
 a HCFC-22 production facility                      Hydrofluorocarbon
 and that destroy more than                         (HFC) gases
 2.14 metric tons of HFC-23                         manufacturing.
 per year.
Hydrogen Production...........             325120  Hydrogen
                                                    manufacturing
                                                    facilities.
Industrial Waste Landfill.....             562212  Solid waste
                                                    landfills.
Industrial Wastewater                      221310  Water treatment
 Treatment.                                         plants.
Injection of Carbon Dioxide...                211  Oil and gas
                                                    extraction.
Iron and Steel Production.....             333110  Integrated iron and
                                                    steel mills, steel
                                                    companies, sinter
                                                    plants, blast
                                                    furnaces, basic
                                                    oxygen process
                                                    furnace (BOPF)
                                                    shops.
Lead Production...............                331  Primary metal
                                                    manufacturing.
Lime Manufacturing............             327410  Lime production.
Magnesium Production..........             331410  Nonferrous metal
                                                    (except aluminum)
                                                    smelting and
                                                    refining: Magnesium
                                                    refining, primary.
Nitric Acid Production........             325311  Nitrogenous
                                                    fertilizer
                                                    manufacturing:
                                                    Nitric acid
                                                    manufacturing.
Petroleum and Natural Gas                  486210  Pipeline
 Systems.                                  221210   transportation of
                                                    natural gas.
                                                   Natural gas
                                                    distribution
                                                    facilities.
                                           211120  Crude petroleum
                                                    extraction.
                                           211130  Natural gas
                                                    extraction.
Petrochemical Production......             324110  Petrochemicals made
                                                    in petroleum
                                                    refineries.
Petroleum Refineries..........             324110  Petroleum refineries.
Phosphoric Acid Production....             325312  Phosphatic fertilizer
                                                    manufacturing.
Pulp and Paper Manufacturing..             322110  Pulp mills.
                                           322120  Paper mills.
                                           322130  Paperboard mills.
                               -----------------------------------------
Miscellaneous Uses of           Facilities included elsewhere.
 Carbonate.
                               -----------------------------------------
Municipal Solid Waste                      562212  Solid waste
 Landfills.                                221320   landfills.
                                                   Sewage treatment
                                                    facilities.
Silicon Carbide Production....             327910  Silicon carbide
                                                    abrasives
                                                    manufacturing.
Soda Ash Production...........             325180  Other basic inorganic
                                                    chemical
                                                    manufacturing: Soda
                                                    ash manufacturing.
Suppliers of Carbon Dioxide...             325120  Industrial gas
                                                    manufacturing
                                                    facilities.
Suppliers of Industrial                    325120  Industrial greenhouse
 Greenhouse Gases.                                  gas manufacturing
                                                    facilities.
Titanium Dioxide Production...             325180  Other basic inorganic
                                                    chemical
                                                    manufacturing:
                                                    Titanium dioxide
                                                    manufacturing.
Underground Coal Mines........             212115  Underground coal
                                                    mining.

[[Page 31804]]

 
Zinc Production...............             331410  Nonferrous metal
                                                    (except aluminum)
                                                    smelting and
                                                    refining: Zinc
                                                    refining, primary.
Suppliers of Coal-based Liquid             211130  Coal liquefaction at
 Fuels.                                             mine sites.
Suppliers of Natural Gas and               221210  Natural gas
 Natural Gas Liquids.                      211112   distribution
                                                    facilities.
                                                   Natural gas liquid
                                                    extraction
                                                    facilities.
Suppliers of Petroleum                     324110  Petroleum refineries.
 Products.
Suppliers of Carbon Dioxide...             325120  Industrial gas
                                                    manufacturing
                                                    facilities.
Suppliers of Industrial                    325120  Industrial greenhouse
 Greenhouse Gases.                                  gas manufacturing
                                                    facilities.
Importers and Exporters of Pre-            423730  Air-conditioning
 charged Equipment and Closed-             333415   equipment (except
 Cell Foams.                                        room units) merchant
                                                    wholesalers.
                                                   Air-conditioning
                                                    equipment (except
                                                    motor vehicle)
                                                    manufacturing.
                                           423620  Air-conditioners,
                                                    room, merchant
                                                    wholesalers.
                                           449210  Electronics and
                                                    appliance retailers.
                                           326150  Polyurethane foam
                                                    products
                                                    manufacturing.
                                           335313  Circuit breakers,
                                                    power,
                                                    manufacturing.
                                           423610  Circuit breakers and
                                                    related equipment
                                                    merchant
                                                    wholesalers.
------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. This table lists the types of facilities that 
the EPA is now aware could potentially be affected by this action. 
Other types of facilities than those listed in the table could also be 
subject to reporting requirements. To determine whether you will be 
affected by this action, you should carefully examine the applicability 
criteria found in 40 CFR part 98, subpart A (General Provisions) and 
each source category. Many facilities that are affected by 40 CFR part 
98 have greenhouse gas emissions from multiple source categories listed 
in table 1 of this preamble. If you have questions regarding the 
applicability of this action to a particular facility, consult the 
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
    Acronyms and abbreviations. The following acronyms and 
abbreviations are used in this document.

ACE Automated Commercial Environment
AIM American Innovation and Manufacturing Act of 2020
ANSI American National Standards Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM ASTM, International
BAMM best available monitoring methods
BCFCs bromochlorofluorocarbons
BEF byproduct emission factor
BFCs bromofluorocarbons
CAA Clean Air Act
CaO calcium oxide (lime)
CARB California Air Resources Board
CAS Chemical Abstracts Service
CBI confidential business information
CBP U.S. Customs and Border Protection
CCS carbon capture and sequestration
CECS combustion emissions control system
CEMS continuous emissions monitoring system
CFC chlorofluorocarbon
CFR Code of Federal Regulations
CF4 perfluoromethane
CGA cylinder gas audit
CHP combined heat and power
CH4 methane
CKD cement kiln dust
CO2 carbon dioxide
CO2e carbon dioxide equivalent
COF2 carbonic difluoride
CRA Congressional Review Act
CSA CSA Group
DAC direct air capture
DCU delayed coking unit
DOC degradable organic carbon
DOE U.S. Department of Energy
DRE destruction or removal efficiency
EAF electric arc furnace
EDC ethylene dichloride
EF emission factor
EGU electricity generating unit
e-GGRT electronic Greenhouse Gas Reporting Tool
EG emission guidelines
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EREF Environmental Research and Education Foundation
F-GHG fluorinated greenhouse gas
F-HTF fluorinated heat transfer fluids
FLIGHT Facility Level Information on Greenhouse Gases Tool
FR Federal Register
FTIR Fourier Transform Infrared
GCCS gas collection and capture system
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GIE gas-insulated equipment
GWP global warming potential
HBCFC hydrobromochlorofluorocarbon
HBFC hydrobromofluorocarbon
HC hydrocarbon
HCFC hydrochlorofluorocarbon
HCFE hydrochlorofluoroether
HFC hydrofluorocarbon
HFE hydrofluoroether
HHV high heating value
HTF heat transfer fluid
HTS Harmonized Tariff System
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change
ISO International Standards Organization
IVT Inputs Verification Tool
k first order decay rate
kg kilogram
kV kilovolt
LCD liquid crystal display
LDC local distribution company
LMOP Landfill Methane Outreach Program
MEMS Microelectromechanical systems
MgO magnesium oxide
mmBtu million British thermal units
MRV monitoring, reporting, and verification plan
MW molecular weight
MSW municipal solid waste
mt metric tons
mtCO2e metric tons carbon dioxide equivalent
MTBS Mean Time Between Service
NAICS North American Industry Classification System
NIST National Institute of Standards and Technology
NSPS new source performance standards
N2O nitrous oxide
OAR Office of Air and Radiation
OMB Office of Management and Budget
OMP operations management plan
PFC perfluorocarbon
POU point of use
POX partial oxidation
ppmv parts per million volume
PRA Paperwork Reduction Act
PSA pressure swing absorption
psi pounds per square inch
psia pounds per square inch, absolute
PV photovoltaic
QA/QC quality assurance/quality control

[[Page 31805]]

RFA Regulatory Flexibility Act
RPC remote plasma cleaning
RY reporting year
scf standard cubic feet
SEM surface-emissions monitoring
SF6 sulfur hexafluoride
SMR steam methane reforming
SSM startup, shutdown, and malfunction
TSD technical support document
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
U.S. United States
VCM vinyl chloride monomer
WGS water gas shift
WMO World Meteorological Organization
WWW World Wide Web

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Executive Summary
    C. Background on This Final Rule
    D. Legal Authority
II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9
III. Final Revisions to Each Subpart of Part 98 and Summary of 
Comments and Responses
    A. Subpart A--General Provisions
    B. Subpart B--Energy Consumption
    C. Subpart C--General Stationary Fuel Combustion
    D. Subpart F--Aluminum Production
    E. Subpart G--Ammonia Manufacturing
    F. Subpart H--Cement Production
    G. Subpart I--Electronics Manufacturing
    H. Subpart N--Glass Production
    I. Subpart P--Hydrogen Production
    J. Subpart Q--Iron and Steel Production
    K. Subpart S--Lime Production
    L. Subpart U--Miscellaneous Uses of Carbonate
    M. Subpart X--Petrochemical Production
    N. Subpart Y--Petroleum Refineries
    O. Subpart AA--Pulp and Paper Manufacturing
    P. Subpart BB--Silicon Carbide Production
    Q. Subpart DD--Electrical Transmission and Distribution 
Equipment Use
    R. Subpart FF--Underground Coal Mines
    S. Subpart GG--Zinc Production
    T. Subpart HH--Municipal Solid Waste Landfills
    U. Subpart OO--Suppliers of Industrial Greenhouse Gases
    V. Subpart PP--Suppliers of Carbon Dioxide
    W. Subpart QQ--Importers and Exporters of Fluorinated Greenhouse 
Gases Contained in Pre-Charged Equipment and Closed-Cell Foams
    X. Subpart RR--Geologic Sequestration of Carbon Dioxide
    Y. Subpart SS--Electrical Equipment Manufacture or Refurbishment
    Z. Subpart UU--Injection of Carbon Dioxide
    AA. Subpart VV--Geologic Sequestration of Carbon Dioxide With 
Enhanced Oil Recovery Using ISO 27916
    BB. Subpart WW--Coke Calciners
    CC. Subpart XX--Calcium Carbide Production
    DD. Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid 
Production
    EE. Subpart ZZ--Ceramics Manufacturing
IV. Final Revisions to 40 CFR Part 9
V. Effective Date of the Final Amendments
VI. Final Confidentiality Determinations
    A. EPA's Approach to Assessing Data Elements
    B. Final Confidentiality Determinations and Emissions Data 
Designations
    C. Final Reporting Determinations for Inputs to Emission 
Equations
VII. Impacts and Benefits of the Final Amendments
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 14094: Modernizing Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act and 1 CFR 
Part 51
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act
    L. Judicial Review

I. Background

A. How is this preamble organized?

    Section I. of this preamble contains background information on the 
June 21, 2022 proposed rule (87 FR 36920, hereafter referred to as 
``2022 Data Quality Improvements Proposal'') and the May 22, 2023 
supplemental proposed rule (88 FR 32852, hereafter referred to as 
``2023 Supplemental Proposal''). This section also discusses the EPA's 
legal authority under the CAA to promulgate (including subsequent 
amendments to) the GHG Reporting Rule, codified at 40 CFR part 98 
(hereinafter referred to as ``part 98''), and the EPA's legal authority 
to make confidentiality determinations for new or revised data elements 
corresponding to these amendments or for existing data elements for 
which the EPA is finalizing a new determination. Section II. of this 
preamble describes the types of amendments included in this final rule. 
Section III. of this preamble is organized by part 98 subpart and 
contains detailed information on the final new requirements for, or 
revisions to, each subpart. Section IV. of this preamble describes the 
final revisions to 40 CFR part 9. Section V. of this preamble explains 
the effective date of the final revisions and how the revisions are 
required to be implemented in reporting year (RY) 2024 and RY2025 
reports. Section VI. of this preamble discusses the final 
confidentiality determinations for new or substantially revised (i.e., 
requiring additional or different data to be reported) data reporting 
elements, as well as for certain existing data elements for which the 
EPA is finalizing a new determination. Section VII. of this preamble 
discusses the impacts of the final amendments. Finally, section VIII. 
of this preamble describes the statutory and Executive order 
requirements applicable to this action.

B. Executive Summary

    The EPA is finalizing certain proposed revisions to part 98 
included in the 2022 Data Quality Improvements Proposal and the 2023 
Supplemental Proposal, with some changes made after consideration of 
public comments. The final amendments include improvements to 
requirements that, broadly, will enhance the quality and the scope of 
information collected, clarify elements of the rule, and streamline 
elements of reporting and recordkeeping. These final revisions include 
a comprehensive update to the global warming potentials (GWPs) in table 
A-1 to subpart A of part 98; updates to provide for collection of 
additional data to understand new source categories or new emission 
sources for specific sectors; updates to emission factors to more 
accurately reflect industry emissions; refinements to existing 
emissions calculation methodologies to reflect an improved 
understanding of emissions sources and end uses of GHGs; additions or 
modifications to reporting requirements in order to eliminate data gaps 
and improve verification of reported emissions; revisions that address 
prior commenter concerns or clarify requirements; and editorial 
corrections that are intended to improve the public's understanding of 
the rule. The final amendments also include streamlining measures such 
as revisions to applicability for certain industry sectors to account 
for changes in usage of certain GHGs or instances where the current 
applicability estimation methodology may overestimate emissions; 
revisions that provide flexibility for or simplify monitoring and 
calculation methods; and revisions to streamline reported data elements 
or recordkeeping where the current requirements are redundant, where 
reported data are not currently useful for verification or analysis, or 
for which continued collection of the data at the same frequency would 
not likely

[[Page 31806]]

provide new insights or knowledge of the industry sector, emissions, or 
trends at this time. This action also finalizes confidentiality 
determinations for the reporting of data elements added or 
substantially revised in these final amendments, and for certain 
existing data elements for which no confidentiality determination has 
been made previously or for which the EPA proposed to revise the 
existing determination.
    In some cases, and as further described in section III. of this 
preamble, the EPA is not taking final action in this final rule on 
certain proposed revisions included in the 2022 Data Quality 
Improvements Proposal and the 2023 Supplemental Proposal. For example, 
after review of comments received in response to the proposed 
requirements to report purchased electricity and thermal energy 
consumption information under the proposed subpart B (Energy 
Consumption), the EPA is not taking action at this time on those 
proposed provisions. The EPA believes additional time is needed to 
consider the comments received before taking final action. Similarly, 
the EPA is not taking final action at this time on certain proposed 
changes for some subparts. In some cases, e.g., for subparts G (Ammonia 
Production), P (Hydrogen Production), S (Lime Production), and HH 
(Municipal Solid Waste Landfills), we are not taking final action at 
this time on certain revisions to the calculation or monitoring 
methodologies that would have revised how data are collected and 
reported in the EPA's electronic greenhouse gas reporting tool (e-
GGRT). In several cases, we are also not taking final action at this 
time on proposed revisions to add reporting requirements. For example, 
under subpart C (General Stationary Fuel Combustion), we are not taking 
final action at this time on proposed revisions to the requirements for 
units in either an aggregation of units or common pipe configuration 
that would have required reporters to provide additional information 
such as the unit type, maximum rated heat input capacity, and fraction 
of the actual total heat input for each unit in the aggregation or the 
common pipe configuration. Also under subpart C, we are not taking 
final action at this time on proposed requirements that would have 
required reporters to identify, for any configuration, whether the unit 
is an electricity generating unit, and, for group configurations (i.e., 
common stack/duct, common pipe, and aggregation of units) that contain 
an electricity generating unit, the estimated decimal fraction of total 
emissions attributable to the electricity generating unit. Similarly, 
we are not taking final action at this time on certain data elements 
that were proposed to be added to subparts A (General Provisions), F 
(Aluminum Production), G, H (Cement Production), P, S, HH, OO 
(Suppliers of Industrial Greenhouse Gases), and QQ (Importers and 
Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged 
Equipment and Closed-Cell Foams). Additional proposed revisions that 
EPA is not taking final action on at this time are discussed in section 
III. of this preamble.
    This final rule also includes an amendment to 40 CFR part 9 to 
include the Office of Management and Budget (OMB) control number issued 
under the Paperwork Reduction Act (PRA) for the information collection 
request for the GHGRP.
    The final amendments will become effective on January 1, 2025. As 
provided under the existing regulations in subpart A of part 98, the 
GWP amendments to table A-1 to subpart A will apply to reports 
submitted by current reporters that are submitted in calendar year 2025 
and subsequent years (i.e., starting with reports submitted for RY2024 
on March 31, 2025). All other final revisions, which apply to both 
existing and new reporters, will be implemented for reports prepared 
for RY2025 and submitted March 31, 2026. Reporters who are newly 
subject to the rule will be required to implement all requirements to 
collect data, including any required monitoring and recordkeeping, on 
January 1, 2025.
    These final amendments are anticipated to result in an overall 
increase in burden for part 98 reporters in cases where the amendments 
expand current applicability, add or revise reporting requirements, or 
require additional emissions data to be reported. The primary burden 
associated with the final rule is due to revisions to applicability, 
including revisions to the global warming potentials in table A-1 to 
subpart A of part 98, that will change the number of reporters 
currently at or near the 25,000 metric tons carbon dioxide equivalent 
(mtCO2e) threshold; revisions to establish requirements for 
new source categories for coke calcining, calcium carbide, caprolactam, 
glyoxal, and glyoxylic acid production, ceramics manufacturing, and 
facilities conducting geologic sequestration of carbon dioxide with 
enhanced oil recovery; and revisions to expand reporting to include new 
emission sources for specific sectors, such as the addition of captive 
(non-merchant) hydrogen production facilities. The final revisions will 
affect approximately 254 new reporters across 13 source categories, 
including the hydrogen production, petroleum and natural gas systems, 
petroleum refineries, electrical transmission and distribution systems, 
industrial wastewater treatment, municipal solid waste landfills, 
fluorinated GHG suppliers, and industrial waste landfills source 
categories, as well as the new source categories added in these final 
revisions. The EPA anticipates some decrease in burden where the final 
revisions will adjust or improve the estimation methodologies for 
determining applicability, simplify calculation methodologies or 
monitoring requirements, or simplify the data that must be reported. In 
several cases, we are also finalizing changes where we anticipate 
increased clarity or more flexibility for reporters that could result 
in a potential decrease in burden. The incremental implementation labor 
costs for all subparts include $2,684,681 in RY2025, and $2,671,831 in 
each subsequent year (RY2026 and RY2027). The incremental 
implementation labor costs over the next three years (RY2025 through 
RY2027) total $8,028,343. There is an additional incremental burden of 
$2,733,937 for capital and operation and maintenance (O&M) costs in 
RY2025 and in each subsequent year (RY2026 and RY2027), which reflects 
changes to applicability and monitoring for subparts with new or 
additional reporters. The incremental non-labor costs for RY2025 
through RY2027 total $8,201,812 over the next three years.

C. Background on This Final Rule

    The GHGRP requires annual reporting of GHG data and other relevant 
information from large facilities and suppliers in the United States. 
In its 2022 Data Quality Improvements Proposal, the EPA proposed 
amendments to specific provisions of part 98 where we identified 
opportunities to improve the quality of the data collected under the 
rule. This included revisions that would provide for the collection of 
additional data that may be necessary to better understand emissions 
from specific sectors or inform future policy decisions under the CAA; 
update emission factors; and refine emissions estimation methodologies. 
The proposed rule also included revisions that provided for the 
collection of additional data that would be useful to improve 
verification of collected data and complement or

[[Page 31807]]

inform other EPA programs. These proposed revisions included the 
incorporation of a new source category to add calculation and reporting 
requirements for quantifying geologic sequestration of CO2 
in association with enhanced oil recovery (EOR) operations. In several 
cases, the 2022 Data Quality Improvements Proposal included revisions 
that would resolve gaps in the current coverage of the GHGRP that leave 
out potentially significant sources of GHG emissions or end uses. The 
EPA also proposed revisions that clarified or updated provisions that 
may be unclear, and that would streamline calculation, monitoring, or 
reporting in specific provisions in part 98 to provide flexibility or 
increase the efficiency of data collection. The EPA included a request 
for comment on expanding the GHGRP to include several new source 
categories (see section IV. of the preamble to the 2022 Data Quality 
Improvements Proposal at 87 FR 37016) and requested comment on 
potential future amendments to add new calculation, monitoring, and 
reporting requirements for these categories. The EPA also proposed 
confidentiality determinations for new or substantially revised data 
reporting elements that would be amended under the proposed rule, as 
well as for certain existing data elements for which the EPA proposed a 
new or revised determination. The EPA received comments on the 2022 
Data Quality Improvements Proposal from June 21, 2022, through October 
6, 2022.
    The EPA subsequently proposed additional amendments to part 98 
where the Agency had received or identified new information to further 
improve the data collected under the GHGRP. The 2023 Supplemental 
Proposal included amendments that were informed by a review of comments 
and information provided by stakeholders on the 2022 Data Quality 
Improvements Proposal, as well as newly proposed amendments that the 
EPA had identified from program implementation, e.g., where additional 
data would improve verification of data reported to the GHGRP or would 
further aid our understanding of changing industry emission trends. The 
2023 Supplemental Proposal included a proposed comprehensive update to 
the GWPs in table A-1 to subpart A of part 98; proposed amendments to 
establish new subparts with specific reporting provisions under part 98 
for five new source categories; and several proposed revisions where 
the EPA had identified new data supporting improvements to the 
calculation, monitoring, and recordkeeping requirements. The 2023 
Supplemental Proposal also clarified or corrected specific proposed 
provisions of the 2022 Data Quality Improvements Proposal. The 
amendments included in the 2023 Supplemental Proposal were proposed as 
part of the EPA's continued efforts to address potential data gaps and 
improve the quality of the data collected in the GHGRP. The EPA also 
proposed confidentiality determinations for new or substantially 
revised data reporting elements that would be revised under the 
supplemental proposed amendments. The EPA received comments on the 2023 
Supplemental Proposal from May 22, 2023, through July 21, 2023.
    The revisions included in the 2022 Data Quality Improvements 
Proposal and the 2023 Supplemental Proposal were based on the EPA's 
assessment of advances in scientific understanding of GHG emissions 
sources, updated guidance on GHG estimation methods, and a review of 
the data collected and emissions trends established following more than 
10 years of implementation of the program. The EPA is finalizing 
amendments and confidentiality determinations in this action, with 
certain changes from the proposed rules following consideration of 
comments submitted and based on the EPA's updated assessment. The 
revisions reflect the EPA's efforts to update and improve the GHGRP by 
better capturing the changing landscape of GHG emissions, providing for 
more complete coverage of U.S. GHG emission sources, and providing a 
more comprehensive approach to understanding GHG emissions. Responses 
to major comments submitted on the proposed amendments from the 2022 
Data Quality Improvement Proposal and the 2023 Supplemental Proposal 
considered in the development of this final rule can be found in 
sections III. and VI. of this preamble. Documentation of all comments 
received as well as the EPA's responses can be found in the document 
``Summary of Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule,'' available in the docket to this rulemaking, 
Docket ID. No. EPA-HQ-OAR-2019-0424.
    This final rule does not address implementation of provisions of 
the Inflation Reduction Act, which was signed into law on August 16, 
2022. Section 60113 of the Inflation Reduction Act amended the CAA by 
adding section 136, ``Methane Emissions and Waste Reduction Incentive 
Program for Petroleum and Natural Gas Systems.'' Although the EPA 
proposed amendments to subpart W of part 98 (Petroleum and Natural Gas 
Systems) in the 2022 Data Quality Improvements Proposal, these were 
developed prior to the Congressional direction provided in CAA section 
136. The EPA noted in the preamble to the 2023 Supplemental Proposal 
(see section I.B., 88 FR 32855) that we intend to issue one or more 
separate actions to implement the requirements of CAA section 136, 
including revisions to certain requirements of subpart W. Subsequently, 
the EPA published a proposed rule for subpart W on August 1, 2023 (88 
FR 50282, hereinafter referred to as the ``2023 Subpart W Proposal''), 
as well as a proposed rule to implement CAA section 136(c), ``Waste 
Emissions Charge,'' that was signed by the Administrator on January 12, 
2024 and published on January 26, 2024 (89 FR 5318),\1\ to comply with 
CAA section 136. As discussed in the 2023 Subpart W Proposal, the EPA 
considered the 2022 Data Quality Improvements Proposal as well as 
additional proposed revisions in the development of the 2023 Subpart W 
Proposal. Accordingly, the EPA is not taking final action on the 
revisions to subpart W, including harmonizing revisions to subparts A 
(General Provisions) and C (General Stationary Fuel Combustion Sources) 
related to subpart W, that were proposed in the 2022 Data Quality 
Improvements Proposal in this final rule.
---------------------------------------------------------------------------

    \1\ CAA section 136(c), ``Waste Emissions Charge,'' directs the 
Administrator to impose and collect a charge on methane 
(CH4) emissions that exceed statutorily specified waste 
emissions thresholds from an owner or operator of an applicable 
facility that reports more than 25,000 metric tons carbon dioxide 
equivalent pursuant to the Greenhouse Gas Reporting Rule's 
requirements for the petroleum and natural gas systems source 
category (codified as subpart W in EPA's Greenhouse Gas Reporting 
Rule regulations).
---------------------------------------------------------------------------

D. Legal Authority

    The EPA is finalizing these rule amendments under its existing CAA 
authority provided in CAA section 114. As stated in the preamble to the 
Mandatory Reporting of Greenhouse Gases final rule (74 FR 56260, 
October 30, 2009), CAA section 114(a)(1) provides the EPA authority to 
require the information gathered by this rule because such data will 
inform and are relevant to the EPA's carrying out of a variety of CAA 
provisions. Thus, when promulgating amendments to the GHGRP, the EPA 
has assessed the reasonableness of requiring the information to be 
provided and explained how the data are relevant to the EPA's ability 
to carry out the provisions of the CAA. See the preambles to the 
proposed GHG

[[Page 31808]]

Reporting Rule (74 FR 16448, April 10, 2009) and the final GHG 
Reporting Rule (74 FR 56260, October 30, 2009) for further discussion 
of this authority. Additionally, in enacting CAA section 136 (discussed 
above in preamble section I.C.), Congress implicitly recognized EPA's 
appropriate use of CAA authority in promulgating the GHGRP. The 
provisions of CAA section 136 reference and are in part based on the 
Greenhouse Gas Reporting Rule requirements under subpart W for the 
petroleum and natural gas systems source category and require further 
revisions to subpart W for purposes of supporting implementation of 
section 136.
    The Administrator has determined that this action is subject to the 
provisions of section 307(d) of the CAA (see also section VIII.L. of 
this preamble). Section 307(d) contains a set of procedures relating to 
the issuance and review of certain CAA rules.
    In addition, pursuant to sections 114, 301, and 307 of the CAA, the 
EPA is publishing final confidentiality determinations for the new or 
substantially revised data elements required by these amendments. 
Section 114(c) requires that the EPA make information obtained under 
section 114 available to the public, except for information (excluding 
emission data) that qualifies for confidential treatment.

II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9

    Relevant to this final rule, the EPA previously proposed revisions 
to part 98 in two separate documents: the 2022 Data Quality 
Improvements Proposal (June 21, 2022, 87 FR 36920) and the 2023 
Supplemental Proposal (May 22, 2023, 88 FR 32852). In the proposed 
rules, the EPA identified two primary categories of revisions that we 
are finalizing in this rule. First, the EPA identified revisions that 
would modify the rule to improve the quality of the data collected and 
better inform the EPA's understanding of U.S. GHG emissions sources. 
Specifically, the EPA identified six types of revisions to improve the 
quality of the data collected under part 98 that we are finalizing in 
this rule, as follows:
     Revisions to table A-1 to the General Provisions of part 
98 to update GWPs to reflect advances in scientific knowledge and 
better characterize the climate impacts of certain GHGs, by including 
values agreed to under the United Nations Framework Convention on 
Climate Change, and to maintain comparability and consistency with the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks (hereafter 
referred to as ``the Inventory'') and other analyses produced by the 
EPA;
     Revisions to expand source categories or add new source 
categories to address potential gaps in reporting of data on U.S. GHG 
emissions or supply in order to improve the accuracy and completeness 
of the data provided by the GHGRP;
     Amendments to update emission factors to incorporate new 
measurement data that more accurately reflect industry emissions;
     Revisions to refine existing emissions calculation 
methodologies to reflect an improved understanding of emissions sources 
and end uses of GHGs, or to incorporate more recent research on GHG 
emissions or formation;
     Additions or modifications to reporting requirements to 
eliminate data gaps and improve verification of emissions estimates; 
and
     Revisions that clarify requirements that reporters have 
previously found vague to ensure that accurate data are being 
collected, and editorial corrections or harmonizing changes that will 
improve the public's understanding of the rule.
    Second, the EPA identified revisions that would streamline the 
calculation, monitoring, or reporting requirements of part 98 to 
provide flexibility or increase the efficiency of data collection. In 
the 2022 Data Quality Improvements Proposal and the 2023 Supplemental 
Notice, the EPA identified several streamlining revisions that we are 
finalizing in this rule, as follows:
     Revisions to applicability criteria for certain industry 
sectors without the 25,000 mtCO2e per year reporting 
threshold to account for changes in usage of certain GHGs, or where the 
current applicability estimation methodology may overestimate 
emissions;
     Revisions that provide flexibility for and simplify 
monitoring and calculation methods where further monitoring and data 
collection will not likely significantly improve our understanding of 
emission sources at this time, or where we currently allow similar less 
burdensome methodologies for other sources; and
     Revisions to reported data elements or recordkeeping where 
the current requirements are redundant or where reported data are not 
currently useful for verification or analysis, or for which continued 
collection of the data at the same frequency will not likely provide 
new insights or knowledge of the industry sector, emissions, or trends 
at this time.
    The revisions included in this final rule will advance the EPA's 
goal of updating the GHGRP to reflect advances in scientific knowledge, 
better reflect the EPA's current understanding of U.S. GHG emissions 
and trends and improve data collection and reporting to better 
understand emissions from specific sectors or inform future policy 
decisions under the CAA. The types of streamlining revisions we are 
finalizing will simplify requirements while maintaining the quality of 
the data collected under part 98, where continued collection of 
information assists in evaluation and support of EPA programs and 
policies.
    The EPA has frequently considered and relied on data collected 
under the GHGRP to carry out provisions of the CAA; to inform policy 
options; and to support regulatory and non-regulatory actions. For 
example, GHGRP landfill data from subpart HH of part 98 (Municipal 
Solid Waste Landfills) were previously analyzed to inform the 
development of the 2016 new source performance standards (NSPS) and 
emission guidelines (EG) for landfills (89 FR 59322; August 29, 2016). 
Specifically, the EPA used data from part 98 reporting to update the 
characteristics and technical attributes of over 1,200 landfills in the 
EPA's landfills data set, as well as to estimate emission reductions 
and costs, to inform the revised performance standards. Most recently, 
the EPA used GHGRP data collected under subparts RR (Geologic 
Sequestration of Carbon Dioxide) and UU (Injection of Carbon Dioxide) 
of part 98 to inform the development of the proposed NSPS and EG for 
GHG emissions from fossil fuel-fired electric generating units (EGUs) 
(88 FR 33240, May 23, 2023, hereafter ``EGU NSPS/EG proposed rule''), 
including to assess the geographic availability of geologic 
sequestration and enhanced oil recovery. These final revisions to the 
GHGRP will, as discussed herein, improve the GHG emissions data and 
supplier data that is collected under the GHGRP to better inform the 
EPA in carrying out provisions of the CAA (such as providing a better 
understanding of upstream production, downstream emissions, and 
potential impacts) and otherwise supporting the continued development 
of climate and air quality standards under the CAA.
    As the EPA has explained since the GHGRP was first promulgated, the 
data also will inform the EPA's implementation of CAA section 103(g) 
regarding improvements in nonregulatory strategies and technologies for 
preventing or reducing air pollutants (e.g., EPA's voluntary

[[Page 31809]]

GHG reduction programs such as the non-CO2 partnership 
programs and ENERGY STAR) (74 FR 56265). The final rule will support 
the overall goals of the GHGRP to collect high-quality GHG data and to 
incorporate metrics and methodologies that reflect scientific updates. 
For example, we are finalizing revisions to table A-1 to subpart A of 
part 98 to update the chemical-specific GWP values of certain GHGs to 
(1) reflect GWPs from the Intergovernmental Panel on Climate Change 
(IPCC) Fifth Assessment Report (hereinafter referred to as ``AR5''); 
\2\ (2) for certain GHGs that do not have chemical-specific GWPs listed 
in AR5, to adopt GWP values from the IPCC Sixth Assessment Report 
(hereinafter referred to as ``AR6''); \3\ and (3) to revise and expand 
the set of default GWPs which are applied to GHGs for which peer-
reviewed chemical-specific GWPs are not available.
---------------------------------------------------------------------------

    \2\ IPCC, 2013: Climate Change 2013: The Physical Science Basis. 
Contribution of Working Group I to the Fifth Assessment Report of 
the Intergovernmental Panel on Climate Change [Stocker, T.F., D. 
Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, 
Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, 
Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs 
are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative 
Efficiencies and Metric Values, which appears on pp. 731-737 of 
Chapter 8, ``Anthropogenic and Natural Radiative Forcing.''
    \3\ Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P. 
Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The 
Earth's Energy Budget, Climate Feedbacks, and Climate Sensitivity 
Supplementary Material. In Climate Change 2021: The Physical Science 
Basis. Contribution of Working Group I to the Sixth Assessment 
Report of the Intergovernmental Panel on Climate Change [Masson-
Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. P[eacute]an, S. 
Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. 
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, 
O. Yelek[ccedil]i, R. Yu, and B. Zhou (eds.)]. Available from 
www.ipcc.ch/ The AR6 GWPs are listed in table 7.SM.7, which appears 
on page 16 of the Supplementary Material.
---------------------------------------------------------------------------

    In several cases, we are finalizing updates to emissions and 
default factors where we have received or identified updated 
measurement data. For example, we are finalizing updates to the default 
biogenic fraction for tire combustion in subpart C of part 98 (General 
Stationary Fuel Combustion) based on updated data obtained by the EPA 
on the weighted average composition of natural rubber in tires, 
allowing for the estimation of an emission factor that is more 
representative of these sources. Similarly, we are finalizing updates 
to the emission factors and default destruction and removal efficiency 
values in subpart I of part 98 (Electronics Manufacturing). The updated 
emission factors are based on newly submitted data from the 2017 and 
2020 technology assessment reports submitted under the GHGRP with 
RY2016 and RY2019 annual reports, as well as consideration of new 
emission factors available in the 2019 Refinement to the 2006 IPCC 
Guidelines for National Greenhouse Gas Inventories (hereafter ``2019 
Refinement'').\4\
---------------------------------------------------------------------------

    \4\ Intergovernmental Panel on Climate Change. 2019 Refinement 
to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 
Calvo Buendia, E., Tanabe, K., Kranjc, A., Baasansuren, J., Fukuda, 
M., Ngarize, S., Osako, A., Pyrozhenko, Y., Shermanau, P. and 
Federici, S. (eds). Published: IPCC, Switzerland. 2019. https://www.ipcc-nggip.iges.or.jp/public/2019rf/.
---------------------------------------------------------------------------

    In other cases, we are finalizing updates to calculation 
methodologies to incorporate updates that are based on an improved 
understanding of emission sources. For example, for subpart I of part 
98 (Electronics Manufacturing), the EPA is implementing emissions 
estimation improvements from the 2019 Refinement such as updates to the 
method used to calculate the fraction of fluorinated input gases and 
byproducts exhausted from tools with abatement systems during stack 
tests; revising equations that calculate the weighted average DREs for 
individual fluorinated greenhouse gases (F-GHGs) across process types; 
requiring that all stack systems be tested if the stack test method is 
used; and updating a set of equations that will more accurately account 
for emissions when pre-control emissions of a F-GHG approach or exceed 
the consumption of that gas during the test period. For subpart Y 
(Petroleum Refineries), we are amending the calculation methodology for 
delayed coking units to more accurately reflect the activities 
conducted at certain facilities that were not captured by the current 
emissions estimation methodology, which relies on a steam generation 
model. The incorporation of updated metrics and methodologies will 
improve the quality and accuracy of the data collected under the GHGRP, 
increase the Agency's understanding of the relative distribution of 
GHGs that are emitted, and better inform EPA policy and programs under 
the CAA.
    The improvements to part 98 will further provide a more 
comprehensive, nationwide GHG emissions profile reflective of the 
origin and distribution of GHG emissions in the United States and will 
more accurately inform EPA policy options for potential regulatory or 
non-regulatory CAA programs. The EPA is finalizing several amendments 
that will reduce gaps in the reporting of GHG emissions and supply from 
specific sectors, including the broadening of existing source 
categories; and establishing new source categories that will add 
calculation, monitoring, reporting, and recordkeeping requirements for 
certain sectors of the economy. The final revisions add five new source 
categories, including coke calcining; ceramics manufacturing; calcium 
carbide production; caprolactam, glyoxal, and glyoxylic acid 
production; and facilities conducting geologic sequestration of carbon 
dioxide with enhanced oil recovery. These source categories were 
identified upon evaluation of emission sources that potentially 
contribute significant GHG emissions that are not currently reported or 
where facilities representative of these source categories may 
currently report under another part 98 source category using 
methodologies that may not provide complete or accurate emissions. 
Additionally, the inclusion of certain source categories will improve 
the completeness of the emissions estimates presented in the Inventory, 
such as collection of data on ceramics manufacturing; calcium carbide 
production; and caprolactam, glyoxal, and glyoxylic acid production. 
The EPA is also finalizing updates to certain subparts to add reporting 
of new emissions or emissions sources for existing sectors to address 
potential gaps in reporting. For example, we are adding requirements 
for the monitoring, calculation, and reporting of F-GHGs other than 
sulfur hexafluoride (SF6) and perfluorocarbons (PFCs) under 
subparts DD (Electrical Equipment and Distribution Equipment Use) and 
SS (Electrical Equipment Manufacture or Refurbishment) to account for 
the introduction of alternative technologies and replacements for 
SF6.
    Likewise, we are finalizing revisions that will improve reporting 
under subpart HH to better account for CH4 emissions from 
these facilities. Following review of recent studies indicating that 
CH4 emissions from landfills may be considerably higher than 
what is currently reported to part 98 due in part to emissions from 
poorly operating gas collection systems or destruction devices, we are 
revising the calculation methodologies in subpart HH to better account 
for these scenarios. These changes are necessary for the EPA to 
continue to analyze the relative emissions and distribution of 
emissions from specific industries, improve the overall quality of the 
data collected under the GHGRP, and better inform future EPA policy and 
programs under the CAA. For example, the final revisions to subpart HH 
will be used to further improve the data in the EPA's landfills data 
set by providing more

[[Page 31810]]

comprehensive and accurate information on landfill emissions and the 
efficacy of gas collection systems and destruction devices.
    The final revisions also help ensure that the data collected in the 
GHGRP can be compared to the data collected and presented by other EPA 
programs under the CAA. For example, we are finalizing several 
revisions to the reporting requirements for subpart HH, including more 
clearly identifying reporting elements associated with each gas 
collection system, each measurement location within a gas collection 
system, and each control device associated with a measurement location 
in subpart HH of part 98. These revisions can be used to estimate the 
relative volume of gas flared versus sent to landfill-gas-to-energy 
projects to better understand the amount of recovered CH4 
that is beneficially used in energy recovery projects. Understanding 
the energy recovery of these facilities is critical for evaluating and 
identifying progress towards renewable energy targets. Specifically, 
these data will allow the Agency to identify industry-specific trends 
of beneficial use of landfill gas, communicate best operating practices 
for reducing GHG emissions, and evaluate options for expanding the use 
of these best practices or other potential policy options under the 
CAA.
    Similarly, we are finalizing revisions to clarify subpart RR 
(Geologic Sequestration of Carbon Dioxide) and add subpart VV (Geologic 
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 
27916) to part 98. Subpart VV provides for the reporting of incidental 
CO2 storage associated with enhanced oil recovery based on 
the CSA Group (CSA)/American National Standards Institute (ANSI) 
International Standards Organization (ISO) 27916:19.
    In the EGU NSPS/EG proposed rule, the EPA proposed that any 
affected EGU that employs CCS technology that captures enough 
CO2 to meet the proposed standard and injects the 
CO2 underground must assure that the CO2 is 
managed at a facility reporting under subpart RR or new subpart VV of 
part 98. As such, this final rule complements the EGU NSPS/EG proposed 
rule.
    In other cases, the revisions include collection of data that could 
be compared to other national and international inventories, improving, 
for example, the estimates provided to the Inventory. For instance, we 
are finalizing revisions to subpart N (Glass Production) to require 
reporting of the annual quantities of cullet (i.e., recycled scrap 
glass) used as a raw material. Because differences in the quantities of 
cullet used can lead to variations in emissions from the production of 
different glass types, the annual quantities of cullet used will 
provide a useful metric for understanding variations and differences in 
emissions estimates as well as improve the analysis, transparency, and 
accuracy of the glass manufacturing sector in the Inventory and other 
EPA programs. Likewise, the addition of reporting for new source 
categories will improve the completeness of the emissions estimates 
presented in the Inventory, such as collection of data on ceramics 
manufacturing, calcium carbide production, and caprolactam, glyoxal, 
and glyoxylic acid production.
    The EPA is finalizing several amendments to improve verification of 
the annual GHG reports. For example, we are finalizing amendments to 
subpart H (Cement Production) to collect additional data including 
annual averages for certain chemical composition input data on a 
facility-basis, which the Agency will use to build verification checks. 
These edits will provide the EPA the ability to check reported 
emissions data from subpart H reporters using both the mass balance and 
direct measurement estimation methods, allowing the EPA to back-
estimate process emissions, which will result in more accurate 
reporting. Similarly, we are amending subparts OO (Suppliers of 
Industrial Greenhouse Gases) and QQ (Importers and Exporters of 
Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or 
Closed-Cell Foams) of part 98 to require reporting of the Harmonized 
Tariff System code for each F-GHG, fluorinated heat transfer fluid (F-
HTF), or nitrous oxide (N2O) shipped, which will reduce 
instances of reporting where the data provided is unclear or unable to 
be compared to outside data sources for verification.
    Lastly, the changes in this final rule will further advance the 
ability of the GHGRP to provide access to quality data on greenhouse 
gas emissions. Since its implementation, the collection of data under 
the GHGRP has allowed the Agency and relevant stakeholders to identify 
changes in industry and emissions trends, such as transitions in 
equipment technology or use of alternative lower-GWP greenhouses gases, 
that may be beneficial for informing other EPA programs under the CAA. 
The GHGRP provides an important data resource for communities and the 
public to understand GHG emissions. Since facilities are required to 
use prescribed calculation and monitoring methods, emissions data can 
be compared and analyzed, including locations of emissions sources. 
GHGRP data are easily accessible to the public via the EPA's online 
data publication tool, also known as FLIGHT at: https://ghgdata.epa.gov/ghgp/main.do. FLIGHT allows users to view and sort GHG 
data for every reporting year starting with 2010 from over 8,000 
entities in a variety of ways including by location, industrial sector, 
and type of GHG emitted. This powerful data resource provides a 
critical tool for communities to identify nearby sources of GHGs and 
provide information to state and local governments. Overall, the final 
revisions in this action will improve the quality of the data collected 
under the program and available to communities.
    These final revisions will, as such, maximize the effectiveness of 
part 98. Section III. of this preamble describes the specific changes 
that we are finalizing for each subpart to part 98 in more detail. 
Additional discussion of the benefits of the final rule are in section 
VII. of this preamble.
    Additionally, we are finalizing a technical amendment to 40 CFR 
part 9 to update the table that lists the OMB control numbers issued 
under the PRA to include the information collection request (ICR) for 
40 CFR part 98. This amendment satisfies the display requirements of 
the PRA and OMB's implementing regulations at 5 CFR part 1320 and is 
further described in section IV. of this preamble.

III. Final Revisions to Each Subpart of Part 98 and Summary of Comments 
and Responses

    This section summarizes the final amendments to each part 98 
subpart, as generally described in section II. of this preamble. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The amendments to each subpart are followed 
by a summary of the major comments on those amendments, and the EPA's 
responses to those comments. Other minor corrections and clarifications 
are reflected in the final redline regulatory text in the docket for 
this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).

A. Subpart A--General Provisions

    The EPA is finalizing several amendments to subpart A of part 98 
(General Provisions) as proposed. In some cases, we are finalizing the 
proposed amendments with revisions. Section III.A.1. of this preamble 
discusses the final revisions to subpart A. The EPA received several 
comments on the proposed subpart A revisions which are discussed in 
section III.A.2.

[[Page 31811]]

of this preamble. We are not finalizing the proposed confidentiality 
determinations for data elements that were included in the proposed 
revisions to subpart A, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart A
    This section summarizes the final amendments to subpart A. Major 
changes in this final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart A can be found in section III.A.2. 
of this preamble. Additional information for these amendments and their 
supporting basis is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions to Global Warming Potentials
    As proposed, we are revising table A-1 to subpart A of part 98 to 
reflect more accurate GWPs to better characterize the climate impacts 
of individual GHGs and to ensure continued consistency with other U.S. 
climate programs, including the Inventory. The amendments to the GWPs 
in table A-1 that we are finalizing in this document are discussed in 
this section of this preamble. The EPA's response to comments received 
on the proposed revisions to table A-1 are in section III.A.2.a. of 
this preamble.
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
two updates to table A-1 to subpart A of part 98 to update GWP values 
to reflect advances in scientific knowledge. First, we proposed to 
adopt a chemical-specific GWP of 0.14 for carbonic difluoride 
(COF2) using the atmospheric lifetime and radiative 
efficiency published by the World Meteorological Organization (WMO) in 
its Scientific Assessment of Ozone Depletion.\5\ We also proposed to 
expand one of the F-GHG groups to which a default GWP is assigned. 
Default GWPs are applied to GHGs for which peer-reviewed chemical-
specific GWPs are not available. Specifically, we proposed to expand 
the ninth F-GHG group in table A-1 to subpart A of part 98, which 
includes unsaturated PFCs, unsaturated HFCs, unsaturated 
hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers, 
unsaturated halogenated esters, fluorinated aldehydes, and fluorinated 
ketones, to include additional unsaturated fluorocarbons. Given the 
very short atmospheric lifetimes of unsaturated GHGs and review of 
available evaluations of individual unsaturated chlorofluorocarbons and 
unsaturated bromofluorocarbons in the 2018 WMO Scientific Assessment, 
we proposed to add unsaturated bromofluorocarbons, unsaturated 
chlorofluorocarbons, unsaturated bromochlorofluorocarbons, unsaturated 
hydrobromofluorocarbons, and unsaturated hydrobromochlorofluorocarbons 
to this F-GHG group, which will apply a default GWP of 1 to these 
compounds. Additional information on these amendments and their 
supporting basis is available in section III.A.1. of the preamble to 
the 2022 Data Quality Improvements Proposal.
---------------------------------------------------------------------------

    \5\ WMO. Scientific Assessment of Ozone Depletion: 2018, Global 
Ozone Research and Monitoring Project-Report No. 58, 588 pp., 
Geneva, Switzerland, 2018. www.esrl.noaa.gov/csd/assessments/ozone/2018/downloads/018OzoneAssessment.pdf. Retrieved July 29, 2019. 
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2019-0424.
---------------------------------------------------------------------------

    As the 2022 Data Quality Improvements Proposal was nearing 
publication, the Parties to the United Nations Framework Convention on 
Climate Change (UNFCCC) fully specified which GWPs countries should use 
for purposes of GHG reporting.\6\ The EPA subsequently proposed a 
comprehensive update to table A-1 to subpart A of part 98 in the 2023 
Supplemental Proposal, consistent with recent science and the UNFCCC 
decision. This update carried out the intent that the EPA expressed at 
the time the GHGRP was first promulgated and in subsequent updates to 
part 98 to periodically update table A-1 as science and UNFCCC 
decisions evolve. Specifically, the EPA proposed revisions to table A-1 
to update the chemical-specific GWPs values of certain GHGs to reflect 
values from the IPCC AR5 \7\ and, for certain GHGs that do not have 
chemical-specific GWPs listed in AR5, to adopt GWP values from the IPCC 
AR6.\8\ We proposed to adopt the AR5 and AR6 GWPs based on a 100-year 
time horizon. We also proposed to revise and expand the set of default 
GWPs in table A-1 for GHGs for which peer-reviewed chemical-specific 
GWPs are not available, including adding two new fluorinated GHG groups 
for saturated chlorofluorocarbons (CFCs) and for cyclic forms of 
unsaturated halogenated compounds, modifying the ninth F-GHG group to 
more clearly apply to non-cyclic unsaturated halogenated compounds, and 
updating the existing default GWP values to reflect values estimated 
from the chemical-specific GWPs that we proposed to adopt from AR5 and 
AR6. See sections II.A. and III.A.1. of the preamble to the 2023 
Supplemental Proposal for additional information.
---------------------------------------------------------------------------

    \6\ As explained in section III.A.1. of the preamble to the 2023 
Supplemental Proposal, the Parties to the UNFCCC specified the 
agreed-on GWPs in November 2021, which was too late to allow the EPA 
to consider proposing a comprehensive GWP update in the 2022 Data 
Quality Improvement Proposal.
    \7\ IPCC, 2013: Climate Change 2013: The Physical Science Basis. 
Contribution of Working Group I to the Fifth Assessment Report of 
the Intergovernmental Panel on Climate Change [Stocker, T.F., D. 
Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, 
Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, 
Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs 
are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative 
Efficiencies and Metric Values, which appears on pp. 731-737 of 
Chapter 8, ``Anthropogenic and Natural Radiative Forcing.''
    \8\ Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P. 
Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The 
Earth's Energy Budget, Climate Feedbacks, and Climate Sensitivity 
Supplementary Material. In Climate Change 2021: The Physical Science 
Basis. Contribution of Working Group I to the Sixth Assessment 
Report of the Intergovernmental Panel on Climate Change [Masson-
Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe[acute]an, S. 
Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. 
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, 
O. Yelek[ccedil]i, R. Yu, and B. Zhou (eds.)]. Available from: 
www.ipcc.ch/. The AR6 GWPs are listed in table 7.SM.7, which appears 
on page 16 of the Supplementary Material.
---------------------------------------------------------------------------

    As proposed, we are amending table A-1 to subpart A of part 98 to 
update and add chemical-specific and default GWPs. Consistent with the 
2021 UNFCCC decision, we are updating table A-1 to use, for GHGs with 
GWPs in AR5, the AR5 GWP values in table 8.A.1 (that reflect the 
climate-carbon feedbacks of CO2 but not the GHG whose GWP is 
being evaluated), and for CH4, the GWP that is not the GWP 
for fossil CH4 in table 8.A.1 (i.e., the GWP for 
CH4 that does not reflect either the climate-carbon 
feedbacks for CH4 or the atmospheric CO2 that 
would result from the oxidation of CH4 in the atmosphere). 
We are also updating table A-1 to adopt AR6 GWP values for 31 F-GHGs 
that have GWPs listed in AR6 but not AR5. Table 2 of this preamble 
lists the final GWP values for each GHG.

[[Page 31812]]



                       Table 2--Revised Chemical-Specific GWPs for Compounds in Table A-1
----------------------------------------------------------------------------------------------------------------
                     Name                           CAS No.              Chemical formula         GWP (100-year)
----------------------------------------------------------------------------------------------------------------
                                             Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Carbon dioxide...............................           124-38-9  CO2...........................               1
Methane......................................            74-82-8  CH4...........................              28
Nitrous oxide................................         10024-97-2  N2O...........................             265
----------------------------------------------------------------------------------------------------------------
                                             Fully Fluorinated GHGs
----------------------------------------------------------------------------------------------------------------
Sulfur hexafluoride..........................          2551-62-4  SF6...........................          23,500
Trifluoromethyl sulphur pentafluoride........           373-80-8  SF5CF3........................          17,400
Nitrogen trifluoride.........................          7783-54-2  NF3...........................          16,100
PFC-14 (Perfluoromethane)....................            75-73-0  CF4...........................           6,630
PFC-116 (Perfluoroethane)....................            76-16-4  C2F6..........................          11,100
PFC-218 (Perfluoropropane)...................            76-19-7  C3F8..........................           8,900
Perfluorocyclopropane........................           931-91-9  c-C3F6........................           9,200
PFC-3-1-10 (Perfluorobutane).................           355-25-9  C4F10.........................           9,200
PFC-318 (Perfluorocyclobutane)...............           115-25-3  c-C4F8........................           9,540
Perfluorotetrahydrofuran.....................           773-14-8  c-C4F8O.......................          13,900
PFC-4-1-12 (Perfluoropentane)................           678-26-2  C5F12.........................           8,550
PFC-5-1-14 (Perfluorohexane, FC-72)..........           355-42-0  C6F14.........................           7,910
PFC-6-1-12...................................           335-57-9  C7F16; CF3(CF2)5CF3...........           7,820
PFC-7-1-18...................................           307-34-6  C8F18; CF3(CF2)6CF3...........           7,620
PFC-9-1-18...................................           306-94-5  C10F18........................           7,190
PFPMIE (HT-70)...............................                 NA  CF3OCF(CF3)CF2OCF2OCF3........           9,710
Perfluorodecalin (cis).......................         60433-11-6  Z-C10F18......................           7,240
Perfluorodecalin (trans).....................         60433-12-7  E-C10F18......................           6,290
Perfluorotriethylamine.......................           359-70-6  N(C2F5)3......................          10,300
Perfluorotripropylamine......................           338-83-0  N(CF2CF2CF3)3.................           9,030
Perfluorotributylamine.......................           311-89-7  N(CF2CF2CF2CF3)3..............           8,490
Perfluorotripentylamine......................           338-84-1  N(CF2CF2CF2CF2CF3)3...........           7,260
----------------------------------------------------------------------------------------------------------------
                   Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
(4s,5s)-1,1,2,2,3,3,4,5-                             158389-18-5  trans-cyc (-CF2CF2CF2CHFCHF-).             258
 octafluorocyclopentane.
HFC-23.......................................            75-46-7  CHF3..........................          12,400
HFC-32.......................................            75-10-5  CH2F2.........................             677
HFC-125......................................           354-33-6  C2HF5.........................           3,170
HFC-134......................................           359-35-3  C2H2F4........................           1,120
HFC-134a.....................................           811-97-2  CH2FCF3.......................           1,300
HFC-227ca....................................        220732-84-8  CF3CF2CHF2....................           2,640
HFC-227ea....................................           431-89-0  C3HF7.........................           3,350
HFC-236cb....................................           677-56-5  CH2FCF2CF3....................           1,210
HFC-236ea....................................           431-63-0  CHF2CHFCF3....................           1,330
HFC-236fa....................................           690-39-1  C3H2F6........................           8,060
HFC-329p.....................................           375-17-7  CHF2CF2CF2CF3.................           2,360
HFC-43-10mee.................................        138495-42-8  CF3CFHCFHCF2CF3...............           1,650
----------------------------------------------------------------------------------------------------------------
                  Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
1,1,2,2,3,3-hexafluorocyclopentane...........        123768-18-3  cyc (-CF2CF2CF2CH2CH2-).......             120
1,1,2,2,3,3,4-heptafluorocyclopentane........       1073290-77-4  cyc (-CF2CF2CF2CHFCH2-).......             231
HFC-41.......................................           593-53-3  CH3F..........................             116
HFC-143......................................           430-66-0  C2H3F3........................             328
HFC-143a.....................................           420-46-2  C2H3F3........................           4,800
HFC-10732....................................           624-72-6  CH2FCH2F......................              16
HFC-10732a...................................            75-37-6  CH3CHF2.......................             138
HFC-161......................................           353-36-6  CH3CH2F.......................               4
HFC-245ca....................................           679-86-7  C3H3F5........................             716
HFC-245cb....................................          1814-88-6  CF3CF2CH3.....................           4,620
HFC-245ea....................................         24270-66-4  CHF2CHFCHF2...................             235
HFC-245eb....................................           431-31-2  CH2FCHFCF3....................             290
HFC-245fa....................................           460-73-1  CHF2CH2CF3....................             858
HFC-263fb....................................           421-07-8  CH3CH2CF3.....................              76
HFC-272ca....................................           420-45-1  CH3CF2CH3.....................             144
HFC-365mfc...................................           406-58-6  CH3CF2CH2CF3..................             804
----------------------------------------------------------------------------------------------------------------
      Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond
----------------------------------------------------------------------------------------------------------------
HFE-125......................................          3822-68-2  CHF2OCF3......................          12,400
HFE-227ea....................................          2356-62-9  CF3CHFOCF3....................           6,450
HFE-329mcc2..................................        134769-21-4  CF3CF2OCF2CHF2................           3,070
HFE-329me3...................................        428454-68-6  CF3CFHCF2OCF3.................           4,550
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-                  3330-15-2  CF3CF2CF2OCHFCF3..............           6,490
 tetrafluoroethoxy)-propane.
----------------------------------------------------------------------------------------------------------------
                             Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-134 (HG-00)..............................          1691-17-4  CHF2OCHF2.....................           5,560
HFE-236ca....................................         32778-11-3  CHF2OCF2CHF2..................           4,240
HFE-236ca12 (HG-10)..........................       7807322-47-1  CHF2OCF2OCHF2.................           5,350
HFE-236ea2 (Desflurane)......................         57041-67-5  CHF2OCHFCF3...................           1,790
HFE-236fa....................................         20193-67-3  CF3CH2OCF3....................             979

[[Page 31813]]

 
HFE-338mcf2..................................        156053-88-2  CF3CF2OCH2CF3.................             929
HFE-338mmz1..................................         26103-08-2  CHF2OCH(CF3)2.................           2,620
HFE-338pcc13 (HG-01).........................        188690-78-0  CHF2OCF2CF2OCHF2..............           2,910
HFE-43-10pccc (H-Galden 1040x, HG-11)........           E1730133  CHF2OCF2OC2F4OCHF2............           2,820
HCFE-235ca2 (Enflurane)......................         13838-16-9  CHF2OCF2CHFCl.................             583
HCFE-235da2 (Isoflurane).....................         26675-46-7  CHF2OCHClCF3..................             491
HG-02........................................        205367-61-9  HF2C-(OCF2CF2)2-OCF2H.........           2,730
HG-03........................................        173350-37-3  HF2C-(OCF2CF2)3-OCF2H.........           2,850
HG-20........................................        249932-25-0  HF2C-(OCF2)2-OCF2H............           5,300
HG-21........................................        249932-26-1  HF2C-OCF2CF2OCF2OCF2O-CF2H....           3,890
HG-30........................................        188690-77-9  HF2C-(OCF2)3-OCF2H............           7,330
1,1,3,3,4,4, 6,6,7,7,9,9, 10,10,12,12,               173350-38-4  HCF2O(CF2CF2O)4CF2H...........           3,630
 13,13,15, 15-eicosafluoro-2,5,8,11,14-
 Pentaoxapentadecane.
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane..         84011-06-3  CHF2CHFOCF3...................           1,240
Trifluoro(fluoromethoxy)methane..............          2261-01-0  CH2FOCF3......................             751
----------------------------------------------------------------------------------------------------------------
                        Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-143a.....................................           421-14-7  CH3OCF3.......................             523
HFE-245cb2...................................         22410-44-2  CH3OCF2CF3....................             654
HFE-245fa1...................................         84011-15-4  CHF2CH2OCF3...................             828
HFE-245fa2...................................          1885-48-9  CHF2OCH2CF3...................             812
HFE-254cb1...................................           425-88-7  CH3OCF2CHF2...................             301
HFE-263fb2...................................           460-43-5  CF3CH2OCH3....................               1
HFE-263m1; R-E-143a..........................           690-22-2  CF3OCH2CH3....................              29
HFE-347mcc3 (HFE-7000).......................           375-03-1  CH3OCF2CF2CF3.................             530
HFE-347mcf2..................................        171182-95-9  CF3CF2OCH2CHF2................             854
HFE-347mmy1..................................       2200732-84-2  CH3OCF(CF3)2..................             363
HFE-347mmz1 (Sevoflurane)....................       2807323-86-6  (CF3)2CHOCH2F.................             216
HFE-347pcf2..................................           406-78-0  CHF2CF2OCH2CF3................             889
HFE-356mec3..................................           382-34-3  CH3OCF2CHFCF3.................             387
HFE-356mff2..................................           333-36-8  CF3CH2OCH2CF3.................              17
HFE-356mmz1..................................         13171-18-1  (CF3)2CHOCH3..................              14
HFE-356pcc3..................................        160620-20-2  CH3OCF2CF2CHF2................             413
HFE-356pcf2..................................         50807-77-7  CHF2CH2OCF2CHF2...............             719
HFE-356pcf3..................................         35042-99-0  CHF2OCH2CF2CHF2...............             446
HFE-365mcf2..................................       2200732-81-9  CF3CF2OCH2CH3.................              58
HFE-365mcf3..................................           378-16-5  CF3CF2CH2OCH3.................            0.99
HFE-374pc2...................................           512-51-6  CH3CH2OCF2CHF2................             627
HFE-449s1 (HFE-7100) Chemical blend..........        163702-07-6  C4F9OCH3......................             421
                                                     163702-08-7  (CF3)2CFCF2OCH3...............
HFE-569sf2 (HFE-7200) Chemical blend.........        163702-05-4  C4F9OC2H5.....................              57
                                                     163702-06-5  (CF3)2CFCF2OC2H5..............
HFE-7300.....................................        132182-92-4  (CF3)2CFCFOC2H5CF2CF2CF3......             405
HFE-7500.....................................        297730-93-9  n-C3F7CFOC2H5CF(CF3)2.........              13
HG'-01.......................................         73287-23-7  CH3OCF2CF2OCH3................             222
HG'-02.......................................        485399-46-0  CH3O(CF2CF2O)2CH3.............             236
HG'-03.......................................        485399-48-2  CH3O(CF2CF2O)3CH3.............             221
Difluoro(methoxy)methane.....................           359-15-9  CH3OCHF2......................             144
2-Chloro-1,1,2-trifluoro-1-methoxyethane.....           425-87-6  CH3OCF2CHFCl..................             122
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane....         22052-86-4  CF3CF2CF2OCH2CH3..............              61
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-        920979-28-8  C12H5F19O2....................              56
 bis[1,2,2,2-tetrafluoro-1-
 (trifluoromethyl)ethyl]-furan.
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane.......           380-34-7  CF3CHFCF2OCH2CH3..............              23
Fluoro(methoxy)methane.......................           460-22-0  CH3OCH2F......................              13
1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl         60598-17-6  CHF2CF2CH2OCH3................            0.49
 2,2,3,3-tetrafluoropropyl ether.
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane..         37031-31-5  CH2FOCF2CF2H..................             871
Difluoro(fluoromethoxy)methane...............           461-63-2  CH2FOCHF2.....................             617
Fluoro(fluoromethoxy)methane.................           462-51-1  CH2FOCH2F.....................             130
----------------------------------------------------------------------------------------------------------------
                                      Saturated Chlorofluorocarbons (CFCs)
----------------------------------------------------------------------------------------------------------------
E-R316c......................................          3832-15-3  trans-cyc (-CClFCF2CF2CClF-)..           4,230
Z-R316c......................................          3934-26-7  cis-cyc (-CClFCF2CF2CClF-)....           5,660
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Formates
----------------------------------------------------------------------------------------------------------------
Trifluoromethyl formate......................         85358-65-2  HCOOCF3.......................             588
Perfluoroethyl formate.......................        313064-40-3  HCOOCF2CF3....................             580
1,2,2,2-Tetrafluoroethyl formate.............        481631-19-0  HCOOCHFCF3....................             470
Perfluorobutyl formate.......................        197218-56-7  HCOOCF2CF2CF2CF3..............             392
Perfluoropropyl formate......................        271257-42-2  HCOOCF2CF2CF3.................             376
1,1,1,3,3,3-Hexafluoropropan-2-yl formate....        856766-70-6  HCOOCH(CF3)2..................             333
2,2,2-Trifluoroethyl formate.................         32042-38-9  HCOOCH2CF3....................              33
3,3,3-Trifluoropropyl formate................       1344118-09-7  HCOOCH2CH2CF3.................              17
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Acetates
----------------------------------------------------------------------------------------------------------------
Methyl 2,2,2-trifluoroacetate................           431-47-0  CF3COOCH3.....................              52
1,1-Difluoroethyl 2,2,2-trifluoroacetate.....       1344118-13-3  CF3COOCF2CH3..................              31
Difluoromethyl 2,2,2-trifluoroacetate........          2024-86-4  CF3COOCHF2....................              27

[[Page 31814]]

 
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate..           407-38-5  CF3COOCH2CF3..................               7
Methyl 2,2-difluoroacetate...................           433-53-4  HCF2COOCH3....................               3
Perfluoroethyl acetate.......................        343269-97-6  CH3COOCF2CF3..................               2
Trifluoromethyl acetate......................         74123-20-9  CH3COOCF3.....................               2
Perfluoropropyl acetate......................       1344118-10-0  CH3COOCF2CF2CF3...............               2
Perfluorobutyl acetate.......................        209597-28-4  CH3COOCF2CF2CF2CF3............               2
Ethyl 2,2,2-trifluoroacetate.................           383-63-1  CF3COOCH2CH3..................               1
----------------------------------------------------------------------------------------------------------------
                                               Carbonofluoridates
----------------------------------------------------------------------------------------------------------------
Methyl carbonofluoridate.....................          1538-06-3  FCOOCH3.......................              95
1,1-Difluoroethyl carbonofluoridate..........       1344118-11-1  FCOOCF2CH3....................              27
----------------------------------------------------------------------------------------------------------------
                             Fluorinated Alcohols Other Than Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
Bis(trifluoromethyl)-methanol................           920-66-1  (CF3)2CHOH....................             182
2,2,3,3,4,4,5,5-Octafluorocyclopentanol......         16621-87-7  cyc (-(CF2)4CH(OH)-)..........              13
2,2,3,3,3-Pentafluoropropanol................           422-05-9  CF3CF2CH2OH...................              19
2,2,3,3,4,4,4-Heptafluorobutan-1-ol..........           375-01-9  C3F7CH2OH.....................              34
2,2,2-Trifluoroethanol.......................            75-89-8  CF3CH2OH......................              20
2,2,3,4,4,4-Hexafluoro-1-butanol.............           382-31-0  CF3CHFCF2CH2OH................              17
2,2,3,3-Tetrafluoro-1-propanol...............            76-37-9  CHF2CF2CH2OH..................              13
2,2-Difluoroethanol..........................           359-13-7  CHF2CH2OH.....................               3
2-Fluoroethanol..............................           371-62-0  CH2FCH2OH.....................             1.1
4,4,4-Trifluorobutan-1-ol....................           461-18-7  CF3(CH2)2CH2OH................            0.05
----------------------------------------------------------------------------------------------------------------
                                 Non-Cyclic, Unsaturated Perfluorocarbons (PFCs)
----------------------------------------------------------------------------------------------------------------
PFC-1114; TFE................................           116-14-3  CF2=CF2; C2F4.................           0.004
PFC-1216; Dyneon HFP.........................           116-15-4  C3F6; CF3CF=CF2...............            0.05
Perfluorobut-2-ene...........................           360-89-4  CF3CF=CFCF3...................            1.82
Perfluorobut-1-ene...........................           357-26-6  CF3CF2CF=CF2..................            0.10
Perfluorobuta-1,3-diene......................           685-63-2  CF2=CFCF=CF2..................           0.003
----------------------------------------------------------------------------------------------------------------
             Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
----------------------------------------------------------------------------------------------------------------
HFC-1132a; VF2...............................            75-38-7  C2H2F2, CF2=CH2...............            0.04
HFC-1141; VF.................................            75-02-5  C2H3F, CH2=CHF................            0.02
(E)-HFC-1225ye...............................          5595-10-8  CF3CF=CHF(E)..................            0.06
(Z)-HFC-1225ye...............................        507328-43-8  CF3CF=CHF(Z)..................            0.22
Solstice 1233zd(E)...........................        102687-65-0  C3H2ClF3; CHCl=CHCF3..........            1.34
HCFO-1233zd(Z)...............................         99728-16-2  (Z)-CF3CH=CHCl................            0.45
HFC-1234yf; HFO-1234yf.......................           754-12-1  C3H2F4; CF3CF=CH2.............            0.31
HFC-1234ze(E)................................          1645-83-6  C3H2F4; trans-CF3CH=CHF.......            0.97
HFC-1234ze(Z)................................         29118-25-0  C3H2F4; cis-CF3CH=CHF;                    0.29
                                                                   CF3CH=CHF.
HFC-1243zf; TFP..............................           677-21-4  C3H3F3, CF3CH=CH2.............            0.12
(Z)-HFC-1336.................................           692-49-9  CF3CH=CHCF3(Z)................            1.58
HFO-1336mzz(E)...............................         66711-86-2  (E)-CF3CH=CHCF3...............              18
HFC-1345zfc..................................           374-27-6  C2F5CH=CH2....................            0.09
HFO-1123.....................................           359-11-5  CHF=CF2.......................           0.005
HFO-1438ezy(E)...............................         14149-41-8  (E)-(CF3)2CFCH=CHF............             8.2
HFO-1447fz...................................           355-08-8  CF3(CF2)2CH=CH2...............            0.24
Capstone 42-U................................         19430-93-4  C6H3F9, CF3(CF2)3CH=CH2.......            0.16
Capstone 62-U................................       2073291-17-2  C8H3F13, CF3(CF2)5CH=CH2......            0.11
Capstone 82-U................................       2160732-58-4  C10H3F17, CF3(CF2)7CH=CH2.....            0.09
(e)-1-chloro-2-fluoroethene..................           460-16-2  (E)-CHCl=CHF..................           0.004
3,3,3-trifluoro-2-(trifluoromethyl)prop-1-ene           382-10-5  (CF3)2C=CH2...................            0.38
----------------------------------------------------------------------------------------------------------------
                                          Non-Cyclic, Unsaturated CFCs
----------------------------------------------------------------------------------------------------------------
CFC-1112.....................................           598-88-9  CClF=CClF.....................            0.13
CFC-1112a....................................            79-35-6  CCl2=CF2......................           0.021
----------------------------------------------------------------------------------------------------------------
                                   Non-Cyclic, Unsaturated Halogenated Ethers
----------------------------------------------------------------------------------------------------------------
PMVE; HFE-216................................          1187-93-5  CF3OCF=CF2....................            0.17
Fluoroxene...................................           406-90-6  CF3CH2OCH=CH2.................            0.05
Methyl-perfluoroheptene-ethers...............                N/A  CH3OC7F13.....................              15
----------------------------------------------------------------------------------------------------------------
                                   Non-Cyclic, Unsaturated Halogenated Esters
----------------------------------------------------------------------------------------------------------------
Ethenyl 2,2,2-trifluoroacetate...............           433-28-3  CF3COOCH=CH2..................           0.008
Prop-2-enyl 2,2,2-trifluoroacetate...........           383-67-5  CF3COOCH2CH=CH2...............           0.007
----------------------------------------------------------------------------------------------------------------
                                        Cyclic, Unsaturated HFCs and PFCs
----------------------------------------------------------------------------------------------------------------
PFC C-1418...................................           559-40-0  c-C5F8........................               2
Hexafluorocyclobutene........................           697-11-0  cyc (-CF=CFCF2CF2-)...........             126
1,3,3,4,4,5,5-heptafluorocyclopentene........          1892-03-1  cyc (-CF2CF2CF2CF=CH-)........              45
1,3,3,4,4-pentafluorocyclobutene.............           374-31-2  cyc (-CH=CFCF2CF2-)...........              92
3,3,4,4-tetrafluorocyclobutene...............          2714-38-7  cyc (-CH=CHCF2CF2-)...........              26
----------------------------------------------------------------------------------------------------------------

[[Page 31815]]

 
                                              Fluorinated Aldehydes
----------------------------------------------------------------------------------------------------------------
3,3,3-Trifluoro-propanal.....................           460-40-2  CF3CH2CHO.....................            0.01
----------------------------------------------------------------------------------------------------------------
                                               Fluorinated Ketones
----------------------------------------------------------------------------------------------------------------
Novec 1230 (perfluoro (2-methyl-3-pentanone))           756-13-8  CF3CF2C(O)CF(CF3)2............             0.1
1,1,1-trifluoropropan-2-one..................           421-50-1  CF3COCH3......................            0.09
1,1,1-trifluorobutan-2-one...................           381-88-4  CF3COCH2CH3...................           0.095
----------------------------------------------------------------------------------------------------------------
                                                  Fluorotelomer
----------------------------------------------------------------------------------------------------------------
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol        185689-57-0  CF3(CF2)4CH2CH2OH.............            0.43
3,3,3-Trifluoropropan-1-ol...................          2240-88-2  CF3CH2CH2OH...................            0.35
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-                          755-02-2  CF3(CF2)6CH2CH2OH.............            0.33
 Pentadecafluorononan-1-ol.
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-           87017-97-8  CF3(CF2)8CH2CH2OH.............            0.19
 Nonadecafluoroundecan-1-ol.
----------------------------------------------------------------------------------------------------------------
                                   Fluorinated GHGs With Carbon-Iodine Bond(s)
----------------------------------------------------------------------------------------------------------------
Trifluoroiodomethane.........................          2314-97-8  CF3I..........................             0.4
----------------------------------------------------------------------------------------------------------------
                             Remaining Fluorinated GHGs with Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Dibromodifluoromethane (Halon 1202)..........            75-61-6  CBr2F2........................             231
2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-          151-67-7  CHBrClCF3.....................              41
 2311/Halothane).
Heptafluoroisobutyronitrile..................         42532-60-5  (CF3)2CFCN....................           2,750
Carbonyl fluoride............................           353-50-4  COF2..........................            0.14
----------------------------------------------------------------------------------------------------------------

    As proposed, we are also amending table A-1 to subpart A of part 98 
to revise the default GWPs. We are modifying the default GWP groups to 
add a group for saturated CFCs and a group for cyclic forms of 
unsaturated halogenated compounds. Based on the numerical differences 
between the GWP for cyclic unsaturated halogenated compounds and non-
cyclic unsaturated halogenated compounds, we are also modifying the 
ninth F-GHG group to reflect non-cyclic forms of unsaturated 
halogenated compounds. The amendments update the default GWPs of each 
group based on the average of the updated chemical-specific GWPs 
(adopted from either the IPCC AR5 or AR6) for the compounds that belong 
to that group. We are also finalizing our proposal to rename the 
fluorinated GHG group ``Other fluorinated GHGs'' to ``Remaining 
fluorinated GHGs.'' The new and revised fluorinated GHG groups and 
their new and revised GWPs are listed in table 3 of this preamble.

     Table 3--Fluorinated GHG Groups and Default GWPs for Table A-1
------------------------------------------------------------------------
           Fluorinated GHG group                   GWP (100-year)
------------------------------------------------------------------------
Fully fluorinated GHGs....................  9,200
Saturated hydrofluorocarbons (HFCs) with    3,000
 two or fewer carbon-hydrogen bonds.
Saturated HFCs with three or more carbon-   840
 hydrogen bonds.
Saturated hydrofluoroethers (HFEs) and      6,600
 hydrochlorofluoroethers (HCFEs) with one
 carbon-hydrogen bond.
Saturated HFEs and HCFEs with two carbon-   2,900
 hydrogen bonds.
Saturated HFEs and HCFEs with three or      320
 more carbon-hydrogen bonds.
Saturated chlorofluorocarbons (CFCs)......  4,900
Fluorinated formates......................  350
Cyclic forms of the following: unsaturated  58
 perfluorocarbons (PFCs), unsaturated
 HFCs, unsaturated CFCs, unsaturated
 hydrochlorofluorocarbons (HCFCs),
 unsaturated bromofluorocarbons (BFCs),
 unsaturated bromochlorofluorocarbons
 (BCFCs), unsaturated
 hydrobromofluorocarbons (HBFCs),
 unsaturated hydrobromochlorofluorocarbons
 (HBCFCs), unsaturated halogenated ethers,
 and unsaturated halogenated esters.
Fluorinated acetates, carbonofluoridates,   25
 and fluorinated alcohols other than
 fluorotelomer alcohols.
Fluorinated aldehydes, fluorinated          1
 ketones, and non-cyclic forms of the
 following: unsaturated PFCs, unsaturated
 HFCs, unsaturated CFCs, unsaturated
 HCFCs, unsaturated BFCs, unsaturated
 BCFCs, unsaturated HBFCs, unsaturated
 HBCFCs, unsaturated halogenated ethers,
 and unsaturated halogenated esters.
Fluorotelomer alcohols....................  1
Fluorinated GHGs with carbon-iodine         1
 bond(s).
Remaining fluorinated GHGs................  1,800
------------------------------------------------------------------------

b. Other Revisions To Improve the Quality of Data Collected for Subpart 
A

    The EPA is finalizing several revisions to improve the quality of 
data collected for subpart A as proposed. In some cases, we are 
finalizing the proposed amendments with revisions. First, we are 
clarifying in 40 CFR 98.2(i)(1) and (2), as proposed, that the 
provision to allow cessation of reporting or ``off-ramping,'' due to 
meeting either the 15,000 mtCO2e level or the 25,000 
mtCO2e level for the number of years specified in 40 CFR 
98.2(i), is based on the CO2e reported, calculated in 
accordance with 40 CFR 98.3(c)(4)(i) (i.e., the annual emissions report 
value as specified in that provision). The final amendments also 
clarify that after an

[[Page 31816]]

owner or operator off-ramps, the owner or operator must use equation A-
1 to subpart A and follow the requirements of 40 CFR 98.2(b)(4) (the 
emission estimation methods used for determination of applicability) in 
subsequent years to determine if emissions exceed the 25,000 
mtCO2e applicability threshold and whether the facility or 
supplier must resume reporting.
    Additionally, the EPA is amending 40 CFR 98.2(f)(1) and adding new 
paragraph (k) as proposed to clarify the calculation of GHG quantities 
for comparison to the 25,000 mtCO2e threshold for importers 
and exporters of industrial greenhouse gases. The final amendments to 
40 CFR 98.2(f)(1) state that importers and exporters must include the 
F-HTFs that are imported or exported during the year. New paragraph (k) 
specifies how to calculate the quantities of F-GHGs and F-HTFs 
destroyed for purposes of comparing them to the 25,000 
mtCO2e threshold for stand-alone industrial F-GHG or F-HTF 
destruction facilities. The EPA is also finalizing as proposed 
revisions to 40 CFR 98.3(h)(4) to limit the total number of days a 
reporter can request to extend the time period for resolving a 
substantive error, either by submitting a revised report or providing 
information demonstrating that the previously submitted report does not 
contain the substantive error, to 180 days. Specifically, the 
Administrator will only approve extension requests for a total of 180 
days from the initial notification of a substantive error. See section 
III.A.1. of the preamble to the 2022 Data Quality Improvements Proposal 
for additional information on these revisions and their supporting 
basis.
    We are finalizing minor clarifications to the reporting and special 
provisions for best available monitoring methods in 40 CFR 98.3(k) and 
(l) as proposed, which apply to owners or operators of facilities or 
suppliers that first become subject to any subpart of part 98 due to 
amendment(s) to table A-1 to subpart A. The final requirements revise 
the term ``published'' to add ``in the Federal Register as a final 
rulemaking'' to clarify the EPA's intent that the requirements apply to 
facilities or suppliers that are first subject to the GHGRP in the year 
after the year the GWP is published as part of a final rule.
    The EPA is finalizing an additional edit to subpart A to the 
electronic reporting provisions of 40 CFR 98.5(b). The revisions 
clarify that 40 CFR 98.5(b) applies to any data that is specified as 
verification software records in a subpart's applicable recordkeeping 
section.
    The EPA is finalizing several revisions to subpart A to incorporate 
new and revised source categories. We are revising tables A-3 and A-4 
to subpart A to clarify the reporting applicability for facilities 
included in the new source categories of coke calcining; ceramics 
manufacturing; calcium carbide production; caprolactam, glyoxal, and 
glyoxylic acid production; and facilities conducting geologic 
sequestration of carbon dioxide with enhanced oil recovery. We are 
revising table A-3 to subpart A to add new subparts that are ``all-in'' 
source categories, including subpart VV (Geologic Sequestration of 
Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916) (section 
III.AA. of this preamble), subpart WW (Coke Calciners) (section III.BB. 
of this preamble), subpart XX (Calcium Carbide Production) (section 
III.CC. of this preamble), and subpart YY (Caprolactam, Glyoxal, and 
Glyoxylic Acid Production) (section III.DD. of this preamble). We are 
revising table A-4 to add new subpart ZZ (Ceramics Manufacturing) and 
assign a threshold of 25,000 mtCO2e, as proposed. As 
discussed in section III.EE. of this preamble, subpart ZZ to part 98 
applies to certain ceramics manufacturing processes that exceed a 
minimum production level (i.e., annually consume at least 2,000 tons of 
carbonates, either as raw materials or as a constituent in clay, heated 
to a temperature sufficient to allow the calcination reaction to occur) 
and that exceed the 25,000 mtCO2e threshold. The revisions 
to tables A-3 and A-4 to subpart A clarify that these new source 
categories apply in RY2025 and future years.
    The EPA is finalizing several revisions to defined terms in 40 CFR 
98.6 as proposed to provide further clarity. These revisions to 
definitions include:
     Revising the definition of ``bulk'' to clarify that the 
import and export of gas includes small containers and does not exclude 
a minimum container size below which reporting will not be required 
(except for small shipments (i.e., those including less than 25 
kilograms)), and to align with the definition of ``bulk'' under the 
American Innovation and Manufacturing Act of 2020 (AIM) regulations at 
40 CFR part 84.
     Revising the definition of ``greenhouse gas or GHG'' to 
clarify the treatment of fluorinated greenhouse gases by removing the 
partial list of fluorinated GHGs currently included in the definition 
and to simply refer to the definition of ``fluorinated greenhouse gas 
(GHG).''
     Adding the acronym ``(GHGs)'' after the term ``fluorinated 
greenhouse gas'' both in the definition of ``greenhouse gas or GHG'' 
and in the definition of ``fluorinated greenhouse gas'' to avoid 
redundancy and potential confusion between the definitions of 
``greenhouse gas'' and ``fluorinated greenhouse gas.''
     Consistent with the revisions of the fluorinated GHG 
groups used to assign default GWPs discussed in section III.A.1.a. of 
this preamble, adding a definition of ``cyclic'' as it applies to 
molecular structures of various fluorinated GHGs; adding definitions of 
``unsaturated chlorofluorocarbons (CFCs),'' ``saturated 
chlorofluorocarbons (CFCs),'' ``unsaturated bromofluorocarbons 
(BFCs),'' ``unsaturated bromochlorofluorocarbons (BCFCs),'' 
``unsaturated hydrobromofluorocarbons (HBFCs),'' and ``unsaturated 
hydrobromochlorofluorocarbons (HBCFCs)''; and revising the definition 
of ``fluorinated greenhouse (GHG) group'' to include the new and 
revised groups.
     Revising the term ``other fluorinated GHGs'' to 
``remaining fluorinated GHGs'' and to revise the definition of the term 
to reflect the new and revised fluorinated GHG groups discussed in 
section III.A.1.a. of this preamble.
     Revising the definition of ``fluorinated heat transfer 
fluids'' and moving it from 40 CFR 98.98 to 98.6 to harmonize with 
changes to subpart OO of part 98 (Suppliers of Industrial Greenhouse 
Gases) (see section III.U. of this preamble). The revised definition 
(1) explicitly includes industries other than electronics 
manufacturing, and (2) excludes most HFCs which are widely used as heat 
transfer fluids outside of electronics manufacturing and are regulated 
under the AIM regulations at 40 CFR part 84.
     Consistent with final revisions to subpart PP (Suppliers 
of Carbon Dioxide) (see section III.V. of this preamble), we are 
finalizing revisions to 40 CFR 98.6 to add a definition for ``Direct 
air capture'' and to amend the definition of ``Carbon dioxide stream.''
    The EPA is making one revision to the definitions in the final rule 
from proposed to correct the definition of ``ASTM''. This change 
updates the definition to include the current name of the standards 
organization, ``ASTM, International''.
    Consistent with final revisions to subparts Q (Iron and Steel 
Production), VV (Geologic Sequestration of Carbon Dioxide with Enhanced 
Oil Recovery Using ISO 27916), WW (Coke Calciners), and XX (Calcium 
Carbide Production), we are finalizing revisions to 40 CFR

[[Page 31817]]

98.7 to incorporate by reference ASTM International (ASTM) E415-17, 
Standard Test Method for Analysis of Carbon and Low-Alloy Steel by 
Spark Atomic Emission Spectrometry (2017) (subpart Q); CSA/ANSI ISO 
27916:19, Carbon dioxide capture, transportation and geological 
storage--Carbon dioxide storage using enhanced oil recovery 
(CO2-EOR) (2019) (subpart VV) (as proposed in the 2023 
Supplemental Proposal); ASTM D3176-15 Standard Practice for Ultimate 
Analysis of Coal and Coke (2015), ASTM D5291-16 Standard Test Methods 
for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (2016), ASTM D5373-21 Standard Test 
Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis 
Samples of Coal and Carbon in Analysis Samples of Coal and Coke (2021), 
and NIST HB 44-2023: Specifications, Tolerances, and Other Technical 
Requirements For Weighing and Measuring Devices, 2023 edition (subpart 
WW); and ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (2008) and ASTM C25-06, Standard Test Methods for Chemical 
Analysis of Limestone, Quicklime, and Hydrated Lime (2006) (subpart 
XX). The EPA has revised the regulatory text of 40 CFR 98.7 from 
proposal to incorporate these revisions and to reorganize the existing 
referenced ASTM standards in alphanumeric order.
    The EPA is not finalizing proposed amendments to subpart A from the 
2022 Data Quality Improvements Proposal that correlate with proposed 
amendments to subpart W of part 98 (Petroleum and Natural Gas Systems) 
from the 2022 Data Quality Improvements Proposal in this action. As 
noted in section I.C. of this preamble, the EPA has issued a subsequent 
proposed rule for subpart W on August 1, 2023, and has reproposed 
related amendments to subpart A in that action. Additionally, the EPA 
is not taking final action at this time on proposed amendments to 
subpart A from the 2023 Supplemental Proposal that were proposed 
harmonizing revisions intended to integrate proposed subpart B (Energy 
Consumption), including proposed reporting and recordkeeping under 40 
CFR 98.2(a)(1), 98.3(c)(4), and 98.3(g)(5). Finally, we are not taking 
final action, at this time, on proposed amendments to 40 CFR 98.7 to 
incorporate by reference standards for electric metering. As discussed 
in section III.B. of this document, the EPA is not taking final action 
on subpart B at this time.
c. Revisions To Streamline and Improve Implementation for Subpart A
    The EPA is finalizing several revisions to subpart A proposed in 
the 2022 Data Quality Improvements Proposal that will streamline and 
improve implementation for part 98. First, we are revising tables A-3 
and table A-4 to subpart A to revise the applicability of subparts DD 
(Electrical Transmission and Distribution Equipment Use) and SS 
(Electrical Equipment Manufacture of Refurbishment) of part 98 as 
proposed. For subpart DD, the final revisions to table A-3 change the 
threshold such that facilities must account for the total estimated 
emissions from F-GHGs, as determined under 40 CFR 98.301 (subpart DD), 
for comparison to a threshold equivalent to 25,000 mtCO2e or 
more per year. We are also moving subpart SS from table A-3 to table A-
4 to subpart A and specifying that subpart SS facilities must account 
for emissions of F-GHGs, as determined under the requirements of 40 CFR 
98.451 (subpart SS), for comparison to a threshold equivalent to 25,000 
mtCO2e or more per year. The final rule updates the 
threshold of subparts DD and SS to be consistent with the threshold set 
for the majority of subparts under part 98, and accounts for additional 
fluorinated gases (including F-GHG mixtures) reported by industry. For 
subpart DD, these final changes also focus Agency resources on the 
substantial emission sources within the sector by excluding facilities 
or operations that may report emissions that are consistently and 
substantially below 25,000 mtCO2e per year. See sections 
III.Q. and III.Y. of this preamble for additional information.
2. Summary of Comments and Responses on Subpart A
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart A. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart A.
a. Comments on Revisions To Global Warming Potentials
    Comment: Several commenters supported the proposed revisions to 
table A-1 to subpart A to update the GWP values to use values from 
table 8.A.1 from the IPCC AR5, and for certain GHGs without GWP values 
listed in AR5, to adopt values from the IPCC AR6. Commenters remarked 
that the updates to the GWP values will be more accurate, align with 
UNFCCC guidance and the Inventory, and provide consistency to reporters 
who may also report under various voluntary standards, such as the GHG 
Protocol or Sustainability Accounting Standards Board.
    Some commenters requested that the EPA clarify the effects of 
changing the GWP (particularly for CH4) on the reported 
total CO2e emissions, despite any actual change in mass 
emissions. The commenters asserted that it is important to inform 
stakeholders that future increases in CO2e emissions due to 
the change in GWP are not reflective of any actual mass emission 
increases and may obscure decreases in annual mass emissions. The 
commenters also recommended that the EPA acknowledge how combustion 
CO2e emissions will be affected.
    Response: In the final rule, the EPA is finalizing its proposal (in 
the 2023 Supplemental Proposal) to adopt the 100-year GWPs from AR5, 
and for certain GHGs without GWPs listed in AR5, to adopt values from 
AR6. Regarding the commenters' concern that the change in GWPs may 
result in apparent, but not real, upward or downward trends in the 
data, the EPA has always published emissions using consistent GWPs for 
every year and will continue to do so. Prior to publication, the EPA 
updates all reported CO2e values to reflect the current GWP 
values in table A-1 to subpart A of part 98. The CO2e 
published by the EPA are based on the same GWP values across all 
reporting years. Hence, there will be no apparent upward or downward 
trend in emissions that are due only to a change in a GWP value.
    Comment: A number of commenters supported the continued use of a 
100-year GWP; one commenter stated that the 100-year GWP is consistent 
with Article 2 of the UNFCCC and that any movement to a framework that 
reduces the mitigation focus on CO2 emissions and adds to 
long-term warming potential compared to the 100-year GWP framework 
would not be well justified. Several commenters specifically commented 
on the proposed GWP for CH4; a number of commenters 
generally supported revising the CH4 GWP value from 25 to 28 
using the 100-year GWP. Other commenters recommended that the EPA 
consider incorporating GWP values on multiple time horizons in the 
reporting requirement, or when publicizing reported emissions. One

[[Page 31818]]

commenter stated that the 100-year GWP does not capture the near-term 
potency of short-lived gases like methane and hydrogen and is 
insufficient to reflect a pollutant's warming power over time. 
Commenters requested that the EPA incorporate the use of additional 
time horizons, such as the 20-year GWP, to acknowledge the near-term 
warming potency of short-lived gases such as CH4, because 
they play a critical role in driving the rate of warming for the near 
future. Commenters argued that the 20-year GWP more accurately 
represents the powerful, short-term impact of methane on the 
atmosphere. Commenters noted that this would also align with several 
state regulatory programs, including California, New York, and New 
Jersey, that currently consider 20-year GWPs. Commenters stressed that 
adopting short-lived climate pollutant strategies and emissions 
controls to limit near-term warming is critical from a policy 
perspective and directly relevant to the EPA's efforts under the Clean 
Air Act. Commenters also requested that historic inventories be updated 
to reflect the role that short-lived climate pollutants play and to 
demonstrate that near-term CH4 emissions reductions are as 
important as long-term CO2 reductions.
    Response: As has been the case since the inception of the GHGRP, we 
are finalizing 100-year GWPs for all GHGs. As noted in the ``Response 
to Comments on Final Rule, Volume 3: General Monitoring Approach, the 
Need for Detailed Reporting, and Other General Rationale Comments'' 
(see Docket ID. No. EPA-HQ-OAR-2008-0508-2260), the EPA selected the 
100-year GWPs because these values are the internationally accepted 
standard for reporting GHG emissions. For example, the parties to the 
UNFCCC agreed to use GWPs that are based on a 100-year time period for 
preparing national inventories, and the reports submitted by other 
signatories to the UNFCCC use GWPs based on a 100-year time period, 
including the GWP for CH4 and certain GHGs identified as 
short-lived climate pollutants. These values were subsequently adopted 
and used in multiple EPA climate initiatives, including the EPA's 
Significant New Alternatives Policy (SNAP) program and the Inventory, 
as well as EPA voluntary reduction partnerships (e.g., Natural Gas 
STAR). Human-influenced climate change occurs on both short (decadal) 
and long (millennial) time scales. While there is no single best way to 
value both short- and long-term impacts in a single metric, the 100-
year GWP is a reasonable approach that has been widely accepted by the 
international community. If the EPA were to adopt a 20-year GWP solely 
for CH4, or for certain other compounds, it would introduce 
a metric that is inconsistent with both the GWPs used for the remaining 
table A-1 gases and with the reporting guidelines issued by the UNFCCC 
and used by the Inventory and other EPA programs. Additionally, the EPA 
and other Federal agencies, which calculate the impact of short-lived 
GHGs using 100-year GWPs, are making reduction of short-lived GHGs a 
priority, such as through the U.S. Global Methane Initiative. In 
addition, it is beneficial for both regulatory agencies and industry to 
use the same GWP values for these GHG compounds because it allows for 
more efficient review of data collected through the GHGRP and other 
U.S. climate programs, reduces potential errors that may arise when 
comparing multiple data sets or converting GHG emissions or supply 
based on separate GWPs, and reduces the burden for reporters and 
agencies to keep track of separate GWPs. For the reasons described 
above, the EPA is retaining a 100-year time horizon as the standard 
metric for defining GWPs in the GHGRP.
b. Comments on Other Revisions To Improve the Quality of Data Collected 
for Subpart A
    Comment: Several commenters opposed the EPA's proposed revisions to 
40 CFR 98.3(h)(4) to limit the total number of days a reporter can 
request to extend the time period for resolving a substantive error, 
either by submitting a revised report or providing information 
demonstrating that the previously submitted report does not contain the 
substantive error, to 180 days. Commenters requested that the Agency 
not put an inflexible cap on the number of days to resolve reporting 
issues; the commenters asserted that the extensions can be helpful for 
newly affected sources, when there is a change in facility ownership, 
and in other situations. One commenter stated that the proposed 
revision may result in arbitrarily short time-periods in which an 
operator may correct an error, especially in cases where the correction 
may not be accepted. The commenter contended that the EPA must add 
additional language to clarify that the 180-day limit will restart if 
the correction is not accepted. Commenters also requested that the EPA 
increase the limit of the total number of days a reporter can request 
an extension beyond the proposed 180 days to provide reporters more 
time to work through the new provisions in the program. One commenter 
requested the EPA restart the 180-day extension request opportunity for 
each instance in which an operator is notified of a substantive error 
or rejected correction (e.g., if a correction is rejected, if 
additional corrections are requested, if corrections span more than one 
reporting year, or if EPA responses to operator questions are delayed).
    Response: The EPA expects that 180 days is a reasonable amount of 
time for a facility to examine company records, gather additional data, 
and/or perform recalculations to submit a revised report or provide the 
necessary information such that the report may be verified. This 
represents more than four 30-day additional extensions beyond the 
initial 45-day period. As noted in the preamble to the final rule 
promulgated on October 30, 2009 (74 FR 52620, hereafter referred to as 
the ``2009 Final Rule''), the EPA concluded that this initial 45-day 
period would be sufficient since facilities have three months from the 
end of a reporting period to submit the initial annual report and have 
already collected and retained data needed for the analyses, so 
revisions to address a known error would likely require less time (see 
74 FR 56278). A subsequent series of extensions of up to an additional 
135 days is a reasonable amount of time to accommodate any additional 
changes that may be needed to the revision.

B. Subpart B--Energy Consumption

    The EPA is not taking final action on the proposed addition of 
subpart B of part 98 (Energy Consumption) in this final rule. The EPA 
received a number of comments for proposed subpart B. See the document 
``Summary of Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to proposed 
subpart B.
    In the 2022 Data Quality Improvements Proposal, the EPA requested 
comment on collecting data on energy consumption in order to improve 
the quality of the data collected under the GHGRP. Specifically, we 
provided background on the EPA's original request for comment on the 
collection of data related to electricity consumption in the 
development of part 98 and the EPA's response in the 2009 Final Rule, 
and requested comment on whether and how the EPA should collect energy 
consumption data in order to support data analyses related to informing 
voluntary energy efficiency

[[Page 31819]]

programs, provide information on industrial sectors where currently 
little data are reported to GHGRP, and inform quality assurance/quality 
control (QA/QC) of the Inventory. We requested comment on specific 
considerations for the potential addition of the energy consumption 
source category (see section IV.F. of the preamble to the 2022 Data 
Quality Improvements Proposal for additional information).
    Following consideration of comments received in response to the 
EPA's request for comment, we subsequently proposed, in the 2023 
Supplemental Proposal, the addition of subpart B to part 98. At that 
time, we reiterated our interest in collecting data on energy 
consumption to gain an improved understanding of the energy intensity 
(i.e., the amount of energy required to produce a given level of 
product or activity, both through on-site energy produced from fuel 
combustion and purchased energy) of specific facilities or sectors, and 
to better inform our understanding of energy needs and the potential 
indirect GHG emissions associated with certain sectors. The proposed 
rule included specific monitoring and reporting requirements for direct 
emitting facilities that report under part 98 and purchase metered 
electricity or metered thermal energy products. In the proposed rule, 
the EPA outlined a source category definition, rationale for the 
proposed applicability of the subpart to direct emitting facilities in 
lieu of a threshold, and specific monitoring, missing data, 
recordkeeping, and reporting requirements. The EPA did not propose 
requirements for facilities to calculate or report indirect emissions 
estimates associated with purchased metered electricity or metered 
thermal energy products. Additional information on the proposed 
amendments is available in the preamble to the 2023 Supplemental 
Proposal.
    In response to the 2022 Data Quality Improvements Proposal and the 
2023 Supplemental Proposal, the EPA received many comments on the 
proposed subpart from a variety of stakeholders providing input on the 
definition, applicability criteria, monitoring, reporting, 
recordkeeping, and additional requirements of the source category, as 
proposed, as well as a number of comments on the EPA's authority to 
collect the energy consumption data proposed under subpart B. The EPA 
is not taking final action on proposed subpart B at this time. The EPA 
intends to further review and consider these comments and other 
relevant information and may consider any next steps on the collection 
of data related to energy consumption in a future rulemaking. 
Therefore, none of the proposed requirements related to subpart B are 
included in this final rule. The EPA is also not taking final action on 
related amendments to subpart A (General Provisions) of part 98 that 
were proposed harmonizing changes for the implementation subpart B, 
including reporting requirements, as discussed in section III.A.1.b. of 
this preamble.

C. Subpart C--General Stationary Fuel Combustion

    The EPA is finalizing several amendments to subpart C of part 98 
(General Stationary Fuel Combustion) as proposed. In some cases, we are 
finalizing the proposed amendments with revisions. In other cases, we 
are not taking final action on the proposed amendments. Section 
III.C.1. of this preamble discusses the final revisions to subpart C. 
The EPA received several comments on the proposed subpart C revisions 
which are discussed in section III.C.2. of this preamble. We are also 
finalizing as proposed confidentiality determinations for new data 
elements resulting from the final revisions to subpart C, as described 
in section VI. of this preamble.

1. Summary of Final Amendments to Subpart C

    This section summarizes the final amendments to subpart C. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart C can be found in this section and 
section III.C.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.

a. Revisions To Improve the Quality of Data Collected for Subpart C

    The EPA is finalizing several revisions to improve the quality of 
data collected for subpart C. First, the EPA is finalizing 
modifications to the Tier 3 calculation methodology, including 
revisions to 40 CFR 98.33(a)(3)(iii) to provide new equations C-5A and 
C-5B, as proposed. The updated equations provide for calculating a 
weighted annual average carbon content and a weighted annual average 
molecular weight, respectively, and correct the calculation method for 
Tier 3 gaseous fuels. The new equations incorporate the molar volume 
conversion factor at standard conditions (as defined at 40 CFR 98.6) 
and, for annual average carbon content, the measured molecular weight 
of the fuel, in order to convert the fuel flow to the appropriate units 
of measure. The final rule includes corrections to the proposed 
paragraph references included in the definition of the variable ``MW'' 
(i.e., molecular weight) to equation C-5.
    The EPA is also finalizing as proposed revisions to provisions 
pertaining to the calculation of biogenic emissions from tire 
combustion. These revisions include:
     Removing the additional provision in 40 CFR 
98.33(b)(1)(vii) on how to apply the threshold to only municipal solid 
waste (MSW) fuel when MSW and tires are both combusted and the reporter 
elects not to separately calculate and report biogenic CO2 
emissions from the combustion of tires, since biogenic CO2 
emissions from tire combustion must now be calculated and reported in 
all cases;
     Removing the language in 40 CFR 98.33(e) and 
98.36(e)(2)(xi) referring to optional biogenic CO2 emissions 
reporting from tire combustion;
     Removing the restriction in 40 CFR 98.33(e)(3)(iv) that 
the default factor that is used to determine biogenic CO2 
emissions may only be used to estimate the annual biogenic 
CO2 emissions from the combustion of tires if the combustion 
of tires represents ``no more than 10 percent annual heat input to a 
unit'';
     Revising 40 CFR 98.33(e)(3)(iv)(A) so that total annual 
CO2 emissions will be calculated using the applicable 
methodology in 40 CFR 98.33(a)(1) through (3) for units using Tier 1 
through 3 for purposes of 40 CFR 98.33(a), and using the Tier 1 
calculation methodology in 40 CFR 98.33(a)(1) for units using the Tier 
4 or part 75 calculation methodologies for purposes of 40 CFR 98.33(a), 
when determining the biogenic component of MSW and/or tires under 40 
CFR 98.33(e)(3)(iv);
     Revising 40 CFR 98.33(e)(3)(iv)(B) to update the default 
factor that is used to determine biogenic CO2 emissions from 
the combustion of tires from 0.20 to 0.24; and
     Correcting 40 CFR 98.34(d) to reference 40 CFR 
98.33(e)(3)(iv) instead of 40 CFR 98.33(b)(1)(vi) and (vii) and 
correcting 40 CFR 98.33(e)(1) to delete the parenthetical clause 
``(except MSW and tires).''
    These final revisions will update the default factor to be based on 
more recent data collected on the average composition of natural rubber 
in tires, remove potentially confusing or conflicting requirements, and 
result in a more accurate characterization of biogenic emissions from 
these sources.

[[Page 31820]]

See section III.B.1. of the preamble to the 2022 Data Quality 
Improvements Proposal for additional information on these revisions and 
their supporting basis. The EPA is also finalizing one additional 
revision related to the estimation of biogenic emissions after 
consideration of comments received on the 2022 Data Quality 
Improvements Proposal. Commenters requested that the EPA expand the 
monitoring requirements at 40 CFR 98.34(e) to include all combined 
biomass and fossil fuels and to allow for testing at one source when a 
common fuel is combusted. The EPA agrees that testing one emission 
source is reasonable when multiple combustion units are fed from a 
common fuel source. Accordingly, the EPA is revising 40 CFR 98.34(e) to 
allow for quarterly ASTM D6866-16 and ASTM D7459-08 testing of one 
representative unit for a common fuel source for all combined biomass 
(or fuels with a biomass component) and fossil fuels. See section 
III.C.2. of this preamble for additional information on related 
comments and the EPA's response.
    We are finalizing corrections to the variable ``R'' in equation C-
11. The term ``R'' is currently defined as ``The number of moles of 
CO2 released upon capture of one mole of the acid gas 
species being removed (R = 1.00 when the sorbent is CaCO3 
and the targeted acid gas species is SO2)'' and is being 
amended to ``The number of moles of CO2 released per mole of 
sorbent used (R = 1.00 when the sorbent is CaCO3 and the 
targeted acid gas species is SO2).'' We are finalizing 
amendments to 40 CFR 98.33(c)(6)(i), (ii), (ii)(A), and (iii)(C), and 
to remove and reserve 40 CFR 98.33(c)(6)(iii)(B) (to clarify the 
methods used to calculate CH4 and N2O emissions 
for blended fuels when heat input is determined after the fuels are 
mixed and combusted), as proposed.
    The EPA identified one additional minor correction to subpart C in 
review of changes for the final rule. Subsequently, we are correcting 
the definition of the term emission factor ``EF'' in equation C-10 from 
``Fuel-specific emission factor for CH4 or N2O, 
from table C-2 of this section'' to ``Fuel-specific emission factor for 
CH4 or N2O, from table C-2 to this subpart.''
    The EPA is finalizing as proposed two additional clarifications to 
the reporting and recordkeeping requirements. We are revising the first 
sentence of 40 CFR 98.36(e)(2)(ii)(C) to clarify that both the annual 
average, and where applicable, monthly high heat values are required to 
be reported. This change clarifies that the annual average high heat 
value is also a reporting requirement (for reporters who do not use the 
electronic inputs verification tool (IVT) within the e-GGRT). We are 
finalizing revisions to the 40 CFR 98.37(b) introductory paragraph and 
paragraphs (b)(9) through (11), (14), (18), (20), (22), and (23) to 
specify recordkeeping data that is currently contained in the file 
generated by the verification software that is already required to be 
retained by reporters under 40 CFR 98.37(b). These revisions correct 
omissions that currently exist in the verification software 
recordkeeping requirements specific to equations C-2a, C-2b, C-3, C-4, 
and C-5. They also align the verification software recordkeeping 
requirements with the final revisions to equation C-5 at 40 CFR 
98.33(a)(3)(iii).
    In the 2022 Data Quality Improvements Proposal, we proposed 
additional reporting requirements, for each unit greater than or equal 
to 10 mmBtu/hour in either an aggregation of units or common pipe 
configuration. The proposed reporting included, for each individual 
unit with maximum rated heat input capacity greater than or equal to 10 
mmBtu/hour included in the group, the unit type, maximum rated heat 
input capacity, and an estimate of the fraction of the total group 
annual heat input attributable to each unit (proposed 40 CFR 
98.36(c)(1)(ii) and (c)(3)(xi)). Following consideration of public 
comments, the EPA is not taking final action on the proposed reporting 
requirements (i.e., identifying the unit type, maximum rated heat input 
capacity, and fraction of the total annual heat input for each unit in 
the aggregation of unit or common pipe). See section III.C.2. of this 
preamble for a summary of the related comments and the EPA's response.
    In the 2023 Supplemental Proposal, the EPA proposed to add a 
requirement to report whether the unit is an EGU for each configuration 
that reports emissions, under either the individual unit provisions at 
40 CFR 98.36(b)(12) or the multi-unit provisions at 40 CFR 
98.36(c)(1)(xii), (c)(2)(xii), and (c)(3)(xii). For multi-unit 
reporting configurations, we also proposed adding a requirement for 
facilities to report an estimated decimal fraction of total emissions 
from the group that are attributable to EGU(s) included in the group. 
Following consideration of public comments, the EPA is not taking final 
action on the proposed revisions to the reporting requirements in this 
rule. See section III.C.2. of this preamble for a summary of the 
related comments and the EPA's response.
    The EPA is also not taking final action in this final rule on 
proposed revisions to subpart C correlated with proposed amendments to 
subpart W (Petroleum and Natural Gas Systems). As noted in section I.C. 
of this preamble, the EPA has issued a subsequent proposed rule for 
subpart W on August 1, 2023 and has reproposed related amendments to 
subpart C in that separate action.
b. Revisions To Streamline and Improve Implementation for Subpart C
    The EPA is finalizing all revisions to streamline and improvement 
implementation for subpart C as proposed. Specifically, the EPA is 
finalizing (1) amendments to 40 CFR 98.34(c)(6) to allow cylinder gas 
audits (CGAs) to be performed using calibration gas concentrations of 
40-60 percent and 80-100 percent of CO2 span, whenever the 
required CO2 span value for a flue gas does is not 
appropriate for the prescribed audit ranges in appendix F of 40 CFR 
part 60; and (2) amendments to provisions in 40 CFR 98.36(c)(1)(vi) and 
98.36(c)(3)(vi) to remove language requiring that facilities with the 
aggregation of units or common pipe configuration types report the 
total annual CO2 mass emissions from all fossil fuels 
combined. See section III.B.2. of the preamble to the 2022 Data Quality 
Improvements Proposal for additional information on these changes and 
their supporting basis.
2. Summary of Comments and Responses on Subpart C
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart C. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart C.
    Comment: One commenter provided a correction to the proposed 
revisions to equation C-5 related to the revisions to the Tier 3 
calculation methodology. The commenter noted that the proposed 
revisions to variable ``MW'' of equation C-5 which specify the 
procedures to be used to determine the annual average molecular weight 
included an incorrect reference to paragraphs (a)(3)(iii)(A)(3) and 
(4), and should point to (a)(3)(iii)(B)(1) and (2).
    Response: We agree that the proposal inadvertently contained 
incorrect cross-references for the variable ``MW'' of equation C-5, and 
the EPA has corrected these cross-references in the final rule.
    Comment: Commenters generally supported the EPA's proposed 
revisions

[[Page 31821]]

to update the calculation methodology for biogenic emissions from tire 
combustion. One commenter requested that the EPA consider expanding the 
requirements of 40 CFR 98.34(e), which requires quarterly testing to 
determine biogenic CO2 when biomass and non-biogenic fuels 
are co-fired in a unit. The commenter noted that 40 CFR 98.34(e) 
currently allows for testing of a single representative unit for 
facilities with multiple units in which tires are the primary fuel 
combusted and the units are fed from a common fuel source. The 
commenter noted that for facilities with multiple units combusting the 
same fuel, testing each source quarterly imposes an additional burden 
without enhancing the accuracy of reported emissions. The commenter 
requested that the EPA expand the provisions to include all combined 
biomass and fossil fuels and to allow for testing one representative 
unit when fuel from a common fuel source is combusted.
    Response: The EPA acknowledges the commenter's support for the 
proposed revisions. The EPA agrees with the commenter that testing one 
emission source when multiple emission sources are fed from a common 
fuel source should be allowed for all combined biomass (or fuels with a 
biomass component) and fossil fuels. Accordingly, the EPA has finalized 
quarterly ASTM D6866-16 and ASTM D7459-08 testing of one representative 
unit for multiple units fed from a common fuel source, for all combined 
biomass (or fuels with a biomass component) and fossil fuels.
    Comment: Some commenters supported the EPA's proposal to revise 40 
CFR 98.36(c)(1) and (3) to require reporting of additional information 
for each unit in either an aggregation of units or common pipe 
configuration (excluding units with maximum rated heat input capacity 
less than 10 mmBtu/hour), including the unit type, maximum rated heat 
input capacity, and an estimate of the fraction of the total annual 
heat input to the unit. These commenters agreed that unit-specific data 
is necessary to understand both the distribution of emissions across 
unit types and sizes, but also the abatement potential through various 
decarbonization strategies (e.g., certain abatement strategies may be 
better suited for certain unit types and uses). The commenters stated 
that the requested data could assist the EPA in the development of NSPS 
or EG under CAA section 111. The commenters noted that, given the 
prevalence of reporting using combined configurations, this data would 
fill large data gaps in the current characterization of industrial 
sectors. One commenter asserted that the requirement should be extended 
to facilities that report using the common stack configuration or the 
alternative part 75 configuration, which would ensure that all 
emissions under the subpart are similarly affected by the proposed 
revisions and would provide a full picture of the GHG abatement 
potential of various source categories. Commenters also requested the 
EPA consider lowering or eliminate the size threshold below 10 mmBtu/
hour; the commenter stated that although smaller units do not account 
for a large share of total capacity, they often present the most viable 
opportunities for greenhouse gas emissions abatement such as 
electrification with heat pump technology.
    Other commenters opposed the proposed requirements. Opposing 
commenters stated that the EPA's explanation for collecting the data 
was ambiguous and did not sufficiently explain what data gaps are 
missing or how the collection of the additional information would 
resolve issues within the currently collected data. One commenter 
opposed disaggregating total emissions from the grouped combustion 
equipment, asserting that aggregating the emissions by individual 
equipment (excluding units rated less than 10 mmBtu/hour) using 
estimation techniques would not provide useful information. Several 
commenters asserted that the proposed approach could not reliably 
provide accurate estimates of actual heat input and is likely not to be 
technically feasible. For example, one commenter stated that the 
physical configuration of certain lime plants would preclude accurate 
unit-specific estimates of actual heat input, as the facilities lack 
certified calibrated meters on a kiln-by-kiln basis and rely on 
quantifying solid fuel usage based on surveys of on-site stockpiles. 
The commenter added that facility-wide reporting of combustion 
emissions satisfies the EPA's objective of developing facility-wide 
emissions information, and additional unit-level information is 
superfluous and of limited value. Other commenters stated that 
individual fuel meters are not common, asserting that annual heat input 
for individual units is often estimated based on the maximum high heat 
input rating and operating hours. One commenter stated that the heat 
input records maintained by facilities do not necessarily correspond to 
the actual heat input of a unit, especially for industries that use 
batching with different process equipment for different products. That 
commenter asserted that actual heat input may vary based on age of the 
unit; how it is utilized in processes for steam, cooling, or other 
purposes; and the high heating value of fuel during certain operating 
periods. Another commenter questioned whether the estimation technique 
proposed would likely undermine the reported data or compromise the 
integrity of actual values that are currently reported. Commenters 
asserted that the requirements would have potentially very limited 
value and may detract from the GHG emission estimates that regulated 
facilities produce for the EPA or other proposed Federal rules.
    Commenters also expressed that the proposed requirements would be 
overly burdensome and significantly increase the recordkeeping and 
reporting burden. One commenter specifically referred to the 
requirement for facilities to estimate the total annual input of each 
unit expressed as a decimal fraction based on the actual heat input of 
each unit compared to the whole; the commenter stated that this 
requirement would essentially negate the time efficiencies gained by 
reporting the aggregated group, especially for reporters using the 
common pipe configuration. The commenter stated that this would 
essentially require that heat inputs be calculated for each piece of 
equipment each year and could result in a ten-fold increase in burden 
for reporters using the common pipe method. Commenters urged that the 
maximum rated heat input of each unit in the aggregated group and 
operating hours should provide enough information for the EPA to 
reasonably approximate emissions for individual equipment.
    Response: Upon careful consideration, the EPA has decided not to 
take final action on the proposed reporting requirements for each unit 
greater than or equal to 10 mmBtu/hour in either an aggregation of 
units or common pipe configuration (the unit type, maximum rated heat 
input capacity, and an estimate of the fraction of the total annual 
heat input attributable to each unit in the group) (proposed 40 CFR 
98.36(c)(1)(ii) and (c)(3)(xi)) at this time. We note that the EPA 
disagrees that estimating the fraction of the actual total annual heat 
input for each unit in the group, based on company records, will be 
overly burdensome to reporters. ``Company records'' is defined in the 
existing part 98 regulations at 40 CFR 98.6 to mean, ``in reference to 
the amount of fuel consumed by a stationary combustion unit (or by a 
group of such units), a complete record of the methods used, the 
measurements made, and the calculations performed to quantify fuel

[[Page 31822]]

usage. Company records may include, but are not limited to, direct 
measurements of fuel consumption by gravimetric or volumetric means, 
tank drop measurements, and calculated values of fuel usage obtained by 
measuring auxiliary parameters such as steam generation or unit 
operating hours. Fuel billing records obtained from the fuel supplier 
qualify as company records.'' The broad definition of company records 
would afford reporters considerable flexibility when it comes to 
estimating the fraction of the actual total annual heat input for each 
unit in the group. The EPA may consider such reporting requirements in 
future rulemakings.
    Comment: Two commenters stated that EGUs should not be reported 
under subpart C and are already reported under subpart D (Electricity 
Generation); one commenter asserted that it is unclear from the 
proposal how reporting these emissions under subpart C would not be 
duplicative. One of the two commenters additionally stated that EGUs 
are not specifically defined in subparts A or C of part 98, and that 
the EPA should provide clarification on the definition of EGUs. The 
commenter added that the proposed requirement would impose burden and 
regulatory confusion because of the conflicting definitions in, and 
applicability of, other EPA regulatory programs which traditionally 
have regulated EGUs separately from non-EGU combustion sources. The 
commenter stated that 40 CFR 98.36(f) already requires sources to 
identify if they are tied to an entity regulated by any public utility 
commission.
    Another commenter suggested a definition for EGUs that aligns with 
a footnote to table A-7 to subpart A that defines EGUs for sources 
reporting under subpart C as ``a fuel-fired electric generator owned or 
operated by an entity that is subject to regulation of customer billing 
rates by the public utilities commission (excluding generators 
connected to combustion units subject to 40 CFR part 98, subpart D) and 
that are located at a facility for which the sum of the nameplate 
capacities for all such electric generators is greater than or equal to 
1 megawatt electric output.''
    One commenter requested clarification that waste heat generation is 
not included; the commenter added that requiring facilities to report 
emissions from the generation of electricity using waste heat recovery 
would be double counting. Other commenters requested clarification that 
emergency generators are exempt from the proposed requirements.
    Two commenters supported the EPA's proposed requirement to allow 
operators to use an engineering estimate of the percentage of 
combustion emissions attributable to facility electricity generation. 
However, another commenter disagreed, stating that the EPA did not 
describe how a reporter would identify such a fraction. The commenter 
added that the EPA failed to take into account that emissions from a 
single combustion unit might provide steam to multiple consumers for 
multiple purposes, only a portion of which includes on-site electricity 
generation. The commenter expressed concerns that, if the rule is 
finalized as proposed, the methods to determine electricity-related 
emissions by fraction could become subject to numerous other 
requirements, such as calculations for GHG emissions, monitoring and 
QA/QC requirements, data reporting, and record retention obligations.
    Response: The EPA is not taking final action on the proposed 
addition of a new indicator that would identify units as electricity 
generating units at this time. Furthermore, the EPA is not taking final 
action on the additional requirement for reporting an estimate of a 
group's total reported emissions attributable to electricity generation 
at this time. As discussed in the preamble to the 2023 Supplemental 
Proposal, under the current subpart C reporting requirements, the EPA 
cannot currently determine the quantity of EGU emissions included in 
the reported total emissions for the subpart. Although some facilities 
currently indicate whether certain stationary fuel combustion sources 
are connected to a fuel-fired electric generator in 40 CFR 98.36(f), 
this requirement only captures a subset of subpart C EGU emissions. The 
EPA therefore intended the proposed reporting requirements to identify 
other EGUs reporting under subpart C in order to improve our 
understanding of subpart C EGU GHG emissions and the attribution of GHG 
emissions to the power plant sector. However, we agree with commenters 
that the proposed requirements could require additional burden not 
contemplated by the proposed rule. Specifically, as noted by 
commenters, we recognize that there could be scenarios in which a 
single combustion unit or group of units may provide steam for multiple 
purposes, only a portion of which includes on-site electricity 
generation. In this case, although a facility may know the quantity of 
electricity generated and could estimate the quantity of steam required 
to generate the electricity, determination of the portion of GHG 
emissions that are attributable to the combustion unit(s) producing the 
steam that is used in an on-site EGU (among other processes) would 
additionally require the estimation of the type and quantity of fuel 
used by each combustion unit for the purposes of producing the steam 
used to generate electricity. For this reason we are not taking final 
action on these requirements in this rule.

D. Subpart F--Aluminum Production

    We are not taking final action on any proposed amendments to 
subpart F of part 98 (Aluminum Production) in this action. In the 2022 
Data Quality Improvements Proposal, the EPA requested comment on 
several issues related to determining emissions from aluminum 
production. Specifically, the EPA requested information on the extent 
to which low voltage emissions have been characterized, if data are 
available to develop guidance on low voltage emission measurements, and 
on the use of the non-linear method as an alternative to the slope 
coefficient and overvoltage methods currently allowed in subpart F. The 
EPA received comments on these issues but is not taking final action on 
any changes to the measurement methodology for subpart F at this time.
    In the 2023 Supplemental Proposal, the EPA proposed revisions to 
the reporting requirements at 40 CFR 98.66(a) and (g) to require that 
facilities report the facility's annual production capacity and annual 
days of operation for each potline. We noted at that time that the 
capacity of the facility and capacity utilization would provide useful 
information for understanding variations in annual emissions and 
emission trends across the sector. The EPA received several comments on 
the proposed subpart F revisions. Following consideration of comments 
received, we are not taking final action on the proposed revisions at 
this time. However, the EPA may consider similar changes to reporting 
requirements in a future rulemaking. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart F.

E. Subpart G--Ammonia Manufacturing

    We are finalizing amendments to subpart G of part 98 (Ammonia 
Manufacturing) as proposed. In some cases, we are finalizing the 
proposed

[[Page 31823]]

amendments with revisions. In other cases, we are not taking final 
action on the proposed amendments. This section discusses the final 
revisions to subpart G. The EPA received only supportive comments for 
the proposed revisions to subpart G. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart G. 
Additional rationale for these amendments is available in the preamble 
to the 2022 Data Quality Improvements Proposal and 2023 Supplemental 
Proposal.
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
several revisions to subpart G to require reporters to report the GHG 
emissions that occur directly from the ammonia manufacturing process 
(i.e., net CO2 process emissions) after subtracting out 
carbon or CO2 captured and used in other products. The 
proposed revisions included combining equation G-4 and equation G-5 
into a new equation G-4 and several harmonizing revisions to 40 CFR 
98.72(a); revisions to the introductory paragraph of 40 CFR 98.73; the 
removal of Sec.  98.73(b)(5); revisions to the introductory paragraph 
of 40 CFR 98.76; and revisions to the reported data elements at 40 CFR 
98.76(b)(1) and (13), as described in section III.C. of the preamble to 
the 2022 Data Quality Improvements Proposal.
    The EPA is finalizing minor edits to 40 CFR 98.72(a), the 
introductory paragraph of 40 CFR 98.73, the introductory paragraph to 
40 CFR 98.76, and 40 CFR 98.76(b)(1) to clarify the term ``ammonia 
manufacturing unit,'' as well as clarifying edits to 40 CFR 
98.76(b)(13) to clearly identify any CO2 used in the 
production of urea and carbon bound in methanol that is intentionally 
produced as a desired product. Additionally, we are finalizing 
clarifying amendments to equation G-1, equation G-2, and equation G-3 
to simplify the equations by removing the process unit ``k'' 
designation in the terms ``CO2,G,k,'' 
``CO2,L,k,'' and ``CO2,S,k.'' We are also 
finalizing the removal of Sec.  98.73(b)(5) and equation G-5, 
consistent with our intent at proposal to require reporting of 
emissions by ammonia manufacturing unit.
    Following consideration of comments received on similar changes 
proposed for subpart S (Lime Manufacturing), the EPA is not taking 
final action at this time on the proposed revisions to allow facilities 
to subtract out carbon or CO2 captured and used in other 
products. We have revised new equation G-4 in the final rule to remove 
the proposed equation terms related to CO2 collected and 
consumed on-site for urea production and the mass of methanol 
intentionally produced as a desired product, and removed text related 
to ``net'' CO2 process emissions. The EPA is also not taking 
final action at this time on the addition of related monthly 
recordkeeping data elements that were proposed as verification software 
records. See section III.K.2. of this preamble for a summary of related 
comments and the EPA's response.
    We are finalizing as proposed one amendment to subpart G from the 
2023 Supplemental Proposal to include a requirement for facilities to 
report the annual quantity of excess hydrogen produced that is not 
consumed through the production of ammonia at 40 CFR 98.76(b)(16). This 
is a harmonizing change to ensure that the final revisions to subpart P 
(Hydrogen Production) to exclude reporting from any process unit for 
which emissions are reported under another subpart of part 98, 
including ammonia production units that report emissions under subpart 
G (see section III.I. of this preamble), will not result in the 
exclusion of reporting of any excess hydrogen production at facilities 
that are subject to subpart G.
    We are also finalizing as proposed related confidentiality 
determinations for data elements resulting from the revisions to 
subpart G, as described in section VI. of this preamble.

F. Subpart H--Cement Production

    We are finalizing several amendments to subpart H of part 98 
(Cement Production) as proposed. In some cases, we are finalizing the 
proposed amendments with revisions. Section III.F.1. of this preamble 
discusses the final revisions to subpart H. The EPA received several 
comments on the proposed subpart H revisions which are discussed in 
section III.F.2. of this preamble. We are also finalizing 
confidentiality determinations for new data elements resulting from the 
revisions to subpart H, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart H
    This section summarizes the final amendments to subpart H. Major 
changes in this final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart H can be found in this section and 
section III.F.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal.
    The EPA is finalizing several revisions to improve the quality of 
data collected for subpart H. First, we are finalizing the addition of 
several new data reporting elements to subpart H under 40 CFR 98.86(a) 
and (b) to enhance the quality and accuracy of the data collected. In 
the 2022 Data Quality Improvements Proposal, the EPA proposed to add 
several data reporting elements based on annual average chemical 
composition data for facilities using either the direct measurement 
(using a continuous emission monitoring system (CEMS)) methodology or 
the mass balance methodology, in order to assist in improving 
verification of reported data. The proposed data elements included (for 
both facilities that report CEMS data and those that report using a 
mass balance method) the annual arithmetic average weight fraction of: 
the total calcium oxide (CaO) content, non-calcined CaO content, total 
magnesium oxide (MgO) content, and non-calcined MgO content of clinker 
at the facility (proposed 40 CFR 98.86(a)(4) through (a)(7) and (b)(19) 
through (b)(22)); and the total CaO content of cement kiln dust (CKD) 
not recycled to the kiln(s), non-calcined CaO content of CKD not 
recycled to the kiln(s), total MgO content of CKD not recycled to the 
kiln(s), and non-calcined MgO content of CKD not recycled to the 
kiln(s) at the facility (proposed 40 CFR 98.86(a)(8) through (11) and 
(b)(23) through (26)). The EPA also proposed to collect other data 
(from both facilities using CEMS and those that report using the mass 
balance method), including annual facility CKD not recycled to the 
kiln(s) in tons (proposed 40 CFR 98.86(a)(12) and (b)(27)) and raw kiln 
feed consumed annually at the facility in tons (dry basis) (proposed 40 
CFR 98.86(a)(13) and (b)(28)), for both verification and to improve the 
methodologies of the Inventory.
    The EPA is finalizing the proposed requirements to report the 
annual arithmetic average weight fraction of the total CaO content, 
non-calcined CaO content, total MgO content, and non-calcined MgO 
content of clinker at the facility (proposed 40 CFR 98.86(a)(4) through 
(7) and (b)(19) through (22)), and the annual facility CKD not recycled 
to the kiln(s) (proposed 40 CFR 98.86(a)(12) and (b)(27), finalized as 
40 CFR 98.86(a)(8) and (b)(27), respectively), for both facilities that 
use CEMS and those that report using the mass balance method. We are 
also finalizing, for facilities using the mass

[[Page 31824]]

balance method, the total CaO content of CKD not recycled to the 
kiln(s), non-calcined CaO content of CKD not recycled to the kiln(s), 
total MgO content of CKD not recycled to the kiln(s), and non-calcined 
MgO content of CKD not recycled to the kiln(s) at the facility 
(proposed 40 CFR 98.86(b)(23) through (26)), and the amount of raw kiln 
feed consumed annually (proposed 40 CFR 98.86(b)(28)). Finalizing these 
data elements will improve the EPA's ability to verify reported 
emissions (e.g., the EPA will be able to create a rough estimate of 
process emissions at the facility and compare that to the reported 
total emissions, and check whether the ratio is within expected 
ranges). For facilities using CEMS, the finalized data elements will 
enable the EPA to estimate process emissions from facilities to provide 
a more accurate national-level cement emissions profile and the 
Inventory. Following consideration of public comments, we are not 
taking final action on certain proposed data elements for facilities 
that report using CEMS. Specifically, the EPA is not taking final 
action on the proposed requirements to report the annual arithmetic 
average of the total CaO content of CKD not recycled to the kiln(s), 
non-calcined CaO content of CKD not recycled to the kiln(s), total MgO 
content of CKD not recycled to the kiln(s), and non-calcined MgO 
content of CKD not recycled to the kiln(s) at the facility (proposed 40 
CFR 98.86(a)(8) through (11)). We are also not taking final action on 
the reporting of the amount of raw kiln feed consumed annually 
(proposed 40 CFR 98.86(a)(13)). See section III.F.2. of this preamble 
for a summary of the related comments and the EPA's response.
    The EPA is finalizing as proposed several clarifications and 
corrections to equations H-1, H-4, and H-5 included in the 2022 Data 
Quality Improvements Proposal. The final revisions to equation H-1 add 
brackets to clarify the summation of clinker and raw material emissions 
for each kiln, and update the definition of parameter 
``CO2 rm'' to ``CO2 rm,m'' and clarify the raw 
material input is on a per-kiln basis. The final revisions to equation 
H-5 revise the inputs ``rm,'' ``CO2 rm'' (revised to 
``CO2 rm,m''), and ``TOCrm,'' and add brackets to 
clarify that emissions are calculated as the sum of emissions from all 
raw materials or raw kiln feed used in the kiln. The final revisions to 
equation H-4 correct the defined parameters for the quarterly non-
calcined CaO content and the quarterly non-calcined MgO content of CKD 
not recycled to ``CKDncCaO'' and ``CKDncMgO,'' 
respectively, to align with the parameters defined in the equation.
2. Summary of Comments and Responses on Subpart H
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart H. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart H.
    Comment: One commenter objected to the EPA's proposed addition of 
data reporting requirements for facilities reporting using the CEMS 
methodology. The commenter asserted that the new data requirements 
would add unnecessary burden without providing additional insight into 
cement industry GHG emissions or improving the quality or accuracy of 
the emissions data provided. The commenter stated that, under the new 
provisions, the EPA would essentially be requiring kilns that are 
currently using CEMS to report their emissions to verify their data by 
using the mass balance method, with associated reporting and 
recordkeeping. The commenter noted that CEMS are already required to 
meet extensive quality assurance and quality control requirements and 
have been determined as the most accurate means of measuring stack 
emissions. Further, the commenter reasoned that the EPA can accurately 
determine process emissions using already reported data, total kiln 
stack emissions data, and combustion emissions data, which they stated 
is included in the confidential monthly clinker production data and 
fuel use data provided using the Tier 4 methodology in subpart C. The 
commenter stated that it is well established by the scientific 
community that process emissions represent 60 percent of CO2 
emissions from the kiln based on the standard chemistry of the cement 
manufacturing process, and that the currently reported data should be 
sufficient.
    The commenter also opposed the EPA's proposed data reporting 
elements for facilities using the mass balance (non-CEMS) methodology, 
likewise insisting that the EPA can readily determine both process and 
combustion emissions from the existing reporting requirements. The 
commenter explained that (1) the reporting of total and non-calcined 
CaO and MgO is irrelevant to calculating CO2 process 
emissions as they are inherently non-carbonate; and (2) in reference to 
the proposed CKD reporting requirement, calculating the CKD not 
recycled and the quantity of raw kiln feed at all kilns within a 
facility would add burden without providing any additional information 
about industry GHG emissions. The commenter also questioned the need 
for the additional data, stating that the EPA did not provide an 
explanation of how the additional data would be used separately from 
potentially verifying process emissions. The commenter also expressed 
concern that the addition of these data elements would justify 
regulatory overreach from other programs.
    Response: We disagree with the commenter's statement that reporting 
additional data from facilities using CEMS will not enhance the EPA's 
verification of the facility reported values. The EPA has encountered 
occasional instances of mistakes in reported CEMS data (e.g., from data 
entry mistakes), resulting in significant errors in reported emissions. 
Fuel use data are not provided to the EPA for cement plants that report 
emissions using CEMS. Currently, fuel use data are entered into the IVT 
to calculate CH4 and N2O emissions from 
combustion for kilns with CEMS, as the process and combustion emissions 
are both vented through the same stack. These IVT data are not directly 
reported to the EPA, so the EPA cannot use them to verify the accuracy 
of reported emissions.
    Furthermore, we are not persuaded by the commenter's assertion that 
process emissions represent 60 percent of kiln emissions. Cement kilns 
can have very different process and combustion emissions depending on 
the input materials, the fuel or energy source used, etc., and an 
average process emissions factor would not be representative of all 
facilities in subpart H. Furthermore, the commenter does not provide 
additional information about how this statistic was calculated and 
whether it is representative of cement manufacturing plants in the 
United States. The commenter did not specify where this statistic can 
be found in the cited source (``Getting the Numbers Right Database, 
Global Cement and Concrete Association'' \9\) and did not provide the 
underlying data to the EPA for review. Importantly, this database 
contains information on global cement production, and emissions 
profiles at facilities in the United States can differ widely from 
those in other countries due to differences in input

[[Page 31825]]

materials, fuels used, and emission control systems that may be in 
place. The EPA has reviewed data, such as those from the UNFCCC, which 
suggest that implied emissions rates may vary from 49-57 percent and 
change by country.\10\
---------------------------------------------------------------------------

    \9\ Available at https://gccassociation.org/sustainability-innovation/gnr-gcca-in-numbers/. Accessed January 9, 2024.
    \10\ United Nations Framework Convention on Climate Change. 
(2023). National inventory submissions 2023. https://unfccc.int/ghg-inventories-annex-i-parties/2023.
---------------------------------------------------------------------------

    Upon careful review and consideration, the EPA has decided not to 
adopt the proposed changes to require the chemical composition data for 
CKD and amount of raw kiln feed consumed annually for facilities 
reporting with CEMS (proposed 40 CFR 98.86(a)(8) through (11) and 
(a)(13)). We are not taking final action on these elements after 
consideration of the comments and in an effort to reduce potential 
burden. The EPA is finalizing the remaining proposed reporting 
requirements as these data elements will improve verification of 
reported emissions. For example, the EPA will be able to create a rough 
estimate of process emissions at the facility and compare that to the 
reported total emissions, and check whether the ratio is within 
expected ranges. We will also be able to build evidence-based 
verification checks on the clinker composition data that is entered by 
facilities that do not use CEMS (we currently have very little 
information on what chemical compositions are typical in cement kilns). 
The final reporting elements will also enable the EPA to estimate 
process emissions from CEMS facilities to provide a more accurate 
national-level emissions profile for the cement industry and the 
Inventory. Reporting average chemical composition data for the clinker 
is expected to be less burdensome for facilities, as this data is 
likely collected as a part of normal business operations, while 
collection of CKD data may be less common. Furthermore, we do not 
believe these additional data elements constitute regulatory overreach 
as they are similar to other data already collected under subpart H and 
will be important for verification and our understanding of process and 
combustion emissions.
    We also disagree that collecting additional data from facilities 
using the mass balance method will not enhance the EPA's verification 
of the facility reported values. Currently clinker composition data are 
entered into the IVT and are not included in the annual report that is 
submitted to the EPA. Reporting of these and additional data elements 
will improve verification of reported emissions and the mass balance 
calculations (e.g., by allowing us to create evidence-based 
verification checks for clinker composition data). The final reporting 
elements will also provide a more accurate national-level emissions 
profile for the cement industry and the Inventory. With respect to the 
burden associated with these added reporting elements for reporters 
using the mass balance reporting method, these data elements are the 
annual arithmetic averages of either monthly or quarterly data elements 
that these reporters already input into e-GGRT through the IVT. These 
data elements are currently entered into the IVT and used for equations 
H-2 through H-5; but they are not reported to the EPA. Thus, the 
burden, if any, is expected to be minimal. There are no changes, as 
compared to the proposal, to the final reporting requirements for 
facilities using the mass balance methodology after consideration of 
this comment.

G. Subpart I--Electronics Manufacturing

    We are finalizing several amendments to subpart I of part 98 
(Electronics Manufacturing) as proposed. In some cases, we are 
finalizing the proposed amendments with revisions. In other cases, we 
are not taking final action on the proposed amendments. Section 
III.G.1. of this preamble discusses the final revisions to subpart I. 
The EPA received several comments on the proposed subpart I revisions 
which are discussed in section III.G.2. of this preamble. We are also 
finalizing as proposed related confidentiality determinations for data 
elements resulting from the revisions to subpart I as described in 
section VI. of this preamble.
1. Summary of Final Amendments to Subpart I
    This section summarizes the final amendments to subpart I. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart I can be found in this section and 
section III.G.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart I
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
several revisions to subpart I to improve data quality, including 
revising the stack testing calculation method, updating the calculation 
methods used to estimate emission factors in the technology assessment 
report, updating existing default emission factors and destruction or 
removal efficiencies (DREs) based on new data, adding a calculation 
method for calculating byproducts produced in abatement systems, 
amending data reporting requirements, and providing clarification on 
reporting requirements. In the 2023 Supplemental Proposal, the EPA 
subsequently proposed corrections to specific revisions from the 2022 
Data Quality Improvements Proposal, including DRE values in table I-16 
and gamma factors in proposed new table I-18 to subpart I of part 98.
    The EPA is finalizing several revisions to 40 CFR 98.93(i) to 
improve the calculation methodology for stack testing. These revisions 
include:
     Adding new equations I-24C and I-24D and a table of 
default weighting factors (new table I-18) to calculate the fraction of 
fluorinated input gases exhausted from tools with abatement systems, 
ai,f, for use in equations I-19A through I-19C and I-21, and 
the fraction of byproducts exhausted from tools with abatement systems, 
ak,i,f, for use in equations I-20 and I-22.
     Revising equations I-24A and I-24B, which calculate the 
weighted average DREs for individual F-GHGs across process types in 
each fab.
     Revising 40 CFR 98.93(i)(3) to require that all stacks be 
tested if the stack test method is used.
     Replacing equation I-19 with a set of equations (i.e., 
equations I-19A, I-19B, and I-19C) that will more accurately account 
for emissions when pre-control emissions of an F-GHG come close to or 
exceed the consumption of that F-GHG during the stack testing period.
     Clarifying the definitions of the variables dif 
and dkif, the average DREs for input gases and byproduct 
gases respectively, in equations I-19A, I-19B, I-19C, and I-19D, in 
equations I-20 through I-22, in equations I-24A and B, and in equation 
I-28 to subpart I.
    These revisions will remove the current requirements to apportion 
gas consumption to different process types, to manufacturing tools 
equipped versus not equipped with abatement systems, and to tested 
versus untested stacks. Equations I-24C and I-24D add the option to 
calculate the fraction of each input gas ``i'' and byproduct gas ``k'' 
exhausted from tools with abatement systems based on the number of 
tools that are equipped versus not equipped with abatement systems, 
along with weighting factors that account for the

[[Page 31826]]

different per-tool emission rates that apply to different process 
types. The weighting factors ([gamma]i,p for input gases and 
[gamma]k,i,p for byproduct gases, provided in table I-18) 
are based on data submitted by semiconductor manufacturers during the 
process of developing the 2019 Refinement (as corrected in the 2023 
Supplemental Proposal). We are finalizing revisions to equations I-24A 
and I-24B, used to calculate the average DRE for each input gas ``i'' 
and byproduct gas ``k,'' based on tool counts and the same weighting 
factors that will be used in equations I-24C and I-24D; this accounts 
for operations in which a facility uses one or more abatement systems 
with a certified DRE value that is different from the default to 
calculate and report controlled emissions. We are finalizing the 
requirement that all stack systems be tested by removing 40 CFR 
98.93(i)(1); this removes not only the need to apportion gas usage to 
tested versus untested stack systems, but also the requirement to 
perform a preliminary calculation of the emissions from each stack 
system. We are finalizing new equations I-19A, I-19B, and I-19C, with a 
clarification, which will more accurately account for emissions when 
emissions of an F-GHG prior to entering any abatement system (i.e., 
pre-control emissions) would approach or exceed the consumption of that 
F-GHG during the stack testing period. We are clarifying that the 0.8 
maximum for the 1-U value only applies to carbon-containing F-GHGs. As 
discussed in the proposal, the modification to the stack testing method 
was intended to accurately account for the source of emissions when the 
measured emissions exceed the consumption of the F-GHG during the stack 
testing period, which may occur in situations where the input gas is 
also generated in significant quantities as a by-product by the other 
input gases. However, it is not expected that NF3 or 
SF6 could be generated as a by-product by a fluorocarbon 
used as an input gas. Therefore, this modification is not appropriate 
and was not intended to apply to SF6 or NF3 
emissions when calculating emissions using the stack test method. The 
revised equations improve upon the current equations because they 
account both for any control of the emissions and for some utilization 
of the input gas. Finally, we are finalizing revisions to the 
definitions of the variables dif and dkif in 
equations I-19A, I-19B, I-19C, and I- 19D, in equations I-20 through I-
22, in equations I-24A and B, and in equation I-28 to clarify that 
these variables reflect the fraction of gas i (or byproduct gas k) that 
is destroyed once gas i (or byproduct gas k) is fed into abatement 
systems. See section III.E.1.a. of the preamble to the 2022 Data 
Quality Improvements Proposal for additional information on these 
revisions and their supporting basis.
    With some changes, the EPA is finalizing revisions to improve the 
quality of the data submitted in the technology assessment reports in 
40 CFR 98.96(y) as proposed in the 2022 Data Quality Improvements 
Proposal. Specifically, the EPA proposed to require that reporters who 
submit a technology assessment report would use three methods (the 
``all-input gas method,'' the ``dominant gas method,'' and the 
``reference emission factor method'') to report the results of each 
emissions test to estimate utilization and byproduct formation emission 
rates. The EPA is finalizing a requirement to report the results using 
two of the three methods proposed, including the all-input gas method, 
with a clarification, and the reference emission factor method, and is 
allowing use of a third method of the reporter's choice, as follows:
     All-input gas method. For input gas emission rates, this 
method attributes all emissions of each F-GHG that is an input gas to 
the input gas emission factor (1-U) factor for that gas, if the input 
gas does not contain carbon or until that 1-U factor reaches 0.8 if the 
input gas does contain carbon, after which emissions of the F-GHG are 
attributed to the other input gases. For byproduct formation rates, 
this method attributes emissions of F-GHG byproducts that are not also 
input gases to all F-GHG input gases (kilogram (kg) of byproduct 
emitted/kg of all F-GHGs used).
     Reference emission factor method. This method estimates 
emissions using the 1-U and the byproduct formation rates that are 
observed in single gas recipes and then adjusts both emission factors 
based on the ratio between the emissions calculated based on the 
factors and the emissions actually observed in the multi-gas process.
     The EPA is finalizing an option for reporters to use, in 
addition to the utilization and byproduct formation rates calculated 
according to the required all-input gas method and the reference 
emission factor method, an alternative method of their choice to 
calculate and report the utilization or byproduct formation rates based 
on the collected data.
    These revisions will ensure that the emission factors submitted in 
the technology assessment reports are robust (for example, not unduly 
affected by changing ratios of input gases) and are comparable to each 
other and to the emission factors already in the EPA's database. The 
EPA proposed, and is finalizing with a clarification, modifications to 
the all-input gas method to avoid an input gas emission factor greater 
than 0.1 when multiple gases are used. The modified method uses 0.8 as 
the maximum 1-U value, and as such, attributes emissions of each F-GHG 
used as an input gas to that input gas until the mass emitted equals 80 
percent of the mass fed into the process (i.e., until the 1-U factor 
equals 0.8). The all-input gas method assigns the remaining emissions 
of the F-GHG to the other input gases as a byproduct in proportion to 
the quantity of each input gas used in the process. We are finalizing 
this modified method with the clarification that the 0.8 maximum for 
the 1-U value only applies to carbon-containing F-GHGs. As discussed in 
the proposal, the modification to the all-input method was intended to 
avoid the situations where the historical methods would violate the 
conservation of mass or fail to reflect the fact that some fraction of 
the input gas reacts with the film it is being used to etch or clean, 
which may occur in situations where the input gas is also generated in 
significant quantities as a by-product by the other input gases. 
However, it is not expected that NF3 or SF6 could 
be generated as a by-product by a fluorocarbon used as an input gas. 
Therefore, this modification is not appropriate and was not intended to 
apply to SF6 or NF3 emissions when calculating 
emission factors. The EPA is requiring use of the all-input gas method 
to facilitate comparisons of new data to historical data; the all-input 
gas method was the most commonly used method in the submitted data sets 
included in technology assessment reports from 2013 and earlier. 
Following consideration of comments received and to reduce burden, the 
EPA is not taking final action on the proposed requirement to report 
emission factors using the dominant gas method. The dominant gas method 
calculates 1-U factors in the same way as the all-input gas method, but 
it calculates byproduct formation rates differently, attributing all 
emissions of F-GHG byproducts to the carbon-containing F-GHG input gas 
accounting for the largest share by mass of the input gases. Additional 
information on each of the three methods is available in section 
III.E.1.b. of the preamble to the 2022 Data Quality Improvements 
Proposal and in the memorandum ``Technical Support for Modifications to 
the Fluorinated

[[Page 31827]]

Greenhouse Gas Emission Estimation Method Option for Semiconductor 
Facilities under Subpart I,'' available in the docket to this 
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. As noted in the 
proposed rule, the EPA intends to make available a calculation workbook 
for the technology assessment report that will calculate the two sets 
of emission factors based on each of the final methods using a single 
set of data entered by the reporter. The option to calculate the 
emission factors using an additional method provides flexibility for 
reporters while enabling comparison between the results of the 
additional method and the results of the two required methods. Where 
reporters choose to submit emission factors using the additional 
method, we will be able to evaluate the reliability and robustness of 
emission factors calculated using all three methods. Additional 
information on comments related to the calculation methods and the 
EPA's response can be found in section III.G.2.a. of this preamble.
    The EPA is also finalizing two additional requirements for the 
submitted technology assessment reports including requiring reporters 
to specify (1) the method used to calculate the reported utilization 
and byproduct formation rates and assign and provide an identifying 
record number for each data set; and (2) for any DRE data submitted, 
whether the abatement system used for the measurement is specifically 
designed to abate the gas measured under the operating condition used 
for the measurement. For reporters who opt to additionally provide 
utilization and byproduct formation rates using an alternative method 
of their choice, reporters must provide this information and a 
description of the alternative method used.
    The EPA is finalizing revisions to update the default emission 
factors and DREs in subpart I based on new data submitted as part of 
the 2017 and 2020 technology assessment reports and the 2019 
Refinement, as proposed in the 2022 Data Quality Improvements Proposal 
and corrected in the 2023 Supplemental Proposal. These revisions 
include:
     Updates to the utilization rates and byproduct emission 
factors (BEFs) for F-GHGs used in semiconductor manufacturing in tables 
I-3, I-4, I-11 and I-12;
     Removal of byproduct emission factors from tables I-3 and 
I-4 where there is a combination of both a low BEF and a low GWP 
resulting in very low reported emissions per metric ton of input gas 
used (removes the BEF for C4F6 and 
C5F8 for all input gases used in wafer cleaning 
or plasma etching processes, and results in not adding BEFs for 
COF2 and C2F4 for any input gas/
process combination from the new data submitted as part of the 2017 and 
2020 technology assessment reports).
     In cases where neither the input gas nor the films being 
processed in the tool contain carbon, setting the BEF for the carbon-
containing byproducts to zero. These provisions apply at the process 
subtype level. For example, a BEF of zero will only be used for a 
combination of input gas and chamber cleaning process subtype (e.g., 
NF3 in remote plasma cleaning (RPC)) if no carbon-containing 
materials were removed using that combination of input gas and chamber 
cleaning process subtype during the year and no carbon-containing input 
gases were used on those tools. Otherwise, the default BEF will be used 
for that combination of input gas and chamber cleaning process subtype 
for all of that gas consumed for that subtype in the fab for the year. 
The EPA is making one modification to the proposed equation to clarify 
that the carbon-containing byproduct emission factors are zero when the 
combination of input gas and etching and wafer cleaning process type 
uses only non-carbon containing input gases (SF6, 
NF3, F2 or other non-carbon input gases) and 
etches or cleans only films that do not contain carbon.
     Updates to the default emission factors for N2O 
used in all electronics manufacturing in table I-8, including distinct 
utilization rates for semiconductor manufacturing and LCD manufacturing 
and, for semiconductor manufacturing, utilization rates by wafer size;
     Revisions to the calculation methodology for MEMS and PV 
manufacturing to allow use of 40 CFR 98.93(a)(1), the current 
methodology for semiconductor manufacturing, for manufacture of MEMS 
and PV using semiconductor tools and processes, which applies the 
default emission factors in tables I-3 and I-4 to these processes;
     Revisions to 40 CFR 98.93(a)(6) to revise the utilization 
rate and byproduct emission factor values assigned to gas/process 
combinations where no default utilization rate is available; these 
revisions account for the likely partial conversion of the input gas 
into CF4 and C2F6. The final rule 
requires, for a gas/process combination where no default input gas 
emission factor is available in tables I-3, I-4, I-5, I-6, and I-7, 
reporters will use an input gas emission factor (1-U) equal to 0.8 
(i.e., a default utilization rate or U equal to 0.2) with BEFs of 0.15 
for CF4 and 0.05 for C2F6.
     Revisions to the default DREs in table I-16 to subpart I 
to reflect new data and strengthening of abatement system certification 
requirements. The final revisions assign chemical-specific DREs to all 
commonly used F-GHGs for the semiconductor manufacturing sub-sector 
without distinguishing between process types.
    Additional information on the EPA's derivation of the final 
emission factors and DREs is available in section III.E.1.c. of the 
preamble to the 2022 Data Quality Improvements Proposal and in the 
revised technical support document, ``Revised Technical Support for 
Revisions to Subpart I: Electronics Manufacturing,'' available in the 
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
    The EPA is also finalizing revisions to the conditions under which 
the default DRE may be claimed, with some revisions from the proposal 
so that the new documentation requirements apply only to abatement 
systems purchased and installed on or after January 1, 2025. For all 
abatement systems for which a DRE is being claimed, including abatement 
systems purchased and installed during or after 2025 and older 
abatement systems, the EPA is maintaining the current certification and 
documentation requirements and is finalizing the proposed additional 
requirement that the certification must contain a manufacturer-verified 
DRE value. If the abatement system is certified to abate the F-GHG or 
N2O at a value equal to or higher than the default DRE, the 
facility may claim the default DRE. If the abatement system is 
certified to abate the F-GHG or N2O but at a value lower 
than the default DRE, the facility may not claim the default; however, 
the facility may claim the lower manufacturer-verified value. (Site-
specific measurements by the electronics manufacturer are still 
required to claim a DRE higher than the default.) Based on annual 
reports submitted through RY2022, facilities have historically been 
able to provide manufacturer-verified DRE values for all abatement 
systems for which emission reductions have been claimed.
    Additional requirements apply to abatement systems purchased and 
installed on or after January 1, 2025. Specifically, the EPA is 
finalizing revisions to the definition of operational mode in 40 CFR 
98.98 to specify that for abatement systems purchased and installed 
during or after January 1, 2025, operational mode means that the system 
is operated within the range of parameters as specified in the DRE 
certification documentation. The specified parameters must include the

[[Page 31828]]

highest total F-GHG or N2O flows and highest total gas flows 
(with N2 dilution accounted for) through the emissions 
control systems. Systems operated outside the range of parameters 
specified in the documentation supporting the DRE certification may 
rely on a measured site-specific DRE according to 40 CFR 98.94(f)(4) to 
be considered operational within the range of parameters used to 
develop a site-specific DRE.
    The EPA is also finalizing revisions to 40 CFR 98.94(f)(3) to 
modify the conditions under which the default or lower DRE may be 
claimed for abatement systems purchased and installed on or after 
January 1, 2025. For systems purchased and installed on or after 
January 1, 2025, reporters are required to: (1) certify that the 
abatement device is able to achieve, under the worst-case flow 
conditions during which the facility is claiming that the system is in 
operational mode, a DRE equal to or greater than either the default DRE 
value, or if the DRE claimed is lower than the default DRE value, a 
manufacturer-verified DRE equal to or greater than the DRE claimed; and 
(2) provide supporting documentation. Specifically, for POU abatement 
devices purchased and installed on or after January 1, 2025, reporters 
must certify and document under 40 CFR 98.94(f)(3)(i) and (ii) that the 
abatement system has been tested by the abatement system manufacturer 
using a scientifically sound, industry-accepted measurement methodology 
that accounts for dilution through the abatement system, such as EPA 
430-R-10-003,\11\ and that the system has been verified to meet (or 
exceed) the destruction or removal efficiency used for that fluorinated 
GHG or N2O under worst-case flow conditions (the highest 
total F-GHG or N2O flows and highest total gas flows, with 
N2 dilution accounted for). Because manufacturers routinely 
conduct DRE testing and are familiar with the protocols of EPA 430-R-
10-003, we anticipate this information will be readily available for 
abatement systems purchased in calendar year 2025 or later. The EPA is 
finalizing that the new DRE requirements will be implemented for 
reports prepared for RY2025 and submitted March 31, 2026, which 
provides over a year for reporters to acquire the necessary 
documentation. Reporters are not required to maintain documentation of 
the DRE on abatement systems for which a DRE is not being claimed.
---------------------------------------------------------------------------

    \11\ Protocol for Measuring Destruction or Removal Efficiency of 
Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, March 2010 (``EPA DRE Protocol''), as 
incorporated at 40 CFR 98.7.
---------------------------------------------------------------------------

    We are also clarifying that the list of abatement system 
manufacturer specifications within which the abatement system must be 
operated at 40 CFR 98.96(q)(2) is intended to be exemplary, adding 
``which may include, for example,'' before the list. This clarifies 
that some of the listed specifications or parameters may not be 
specified by all abatement system manufacturers for all abatement 
systems, and leaves open the possibility that some abatement system 
manufacturers may include other specifications within which the 
abatement system must be operated.
    Additionally, following consideration of comments received, we are 
clarifying how reporters account for uptime of the abatement device if 
suitable backup emissions control equipment or interlocking with the 
process tool is implemented for each emissions control system. The EPA 
is revising the definition of the term ``UTij'' in equation 
I-15 and the definition of ``UTf'' in equation I-23 to 
clarify that if all the abatement systems for the relevant input gas 
and process type are interlocked with all the tools feeding them, the 
uptime may be set to one (1). We are also clarifying equations I-15 and 
I-23 to reference the provisions in 40 CFR 98.94(f)(4)(vi) when 
accounting for uptime when redundant abatement systems are used. See 
section III.G.2.a. of this preamble for additional information on 
related comments and the EPA's response.
    The EPA is finalizing the addition of a calculation methodology 
that estimates the emissions of CF4 produced in hydrocarbon-
fuel based combustion emissions control systems (``HC fuel CECs'') that 
are not certified not to generate CF4. Following 
consideration of public comments, the calculation will be required only 
for HC fuel CECs purchased and installed on or after January 1, 2025. 
To implement the new calculation methodology, we are adding a new 
equation I-9 and renumbering the previous equation I-9 as equation I-
8B. Equation I-9 only applies to processes that use F2 as an 
input gas or to remote plasma cleaning processes that use 
NF3 as an input gas. Equation I-9 estimates the emissions of 
CF4 from generation in emissions control systems by 
calculating the mass of the fluorine entering uncertified HC fuel CECs 
(the product of the consumption of the input gas, the emission factor 
for fluorine, and ai, where ai is the ratio of 
the number of tools with uncertified abatement devices for the gas-
process combination to the total number of process tools for the gas-
process combination) and multiplying that mass by a CF4 
emission factor, ABCF4,F2, which has a value of 0.116. In 
related changes, the EPA is finalizing a BEF for F2 from 
NF3 used in remote plasma clean processes of 0.5. For other 
gas and process combinations where no data are available (listed as 
``NA'' in tables I-3 and I-4), the EPA is finalizing a BEF of 0.8 be 
used for F2 in equation I-9 for all process types.
    The EPA is requiring that reporters estimate CF4 
emissions from all HC fuel CECs that are purchased and installed on or 
after January 1, 2025 and that are not certified not to produce 
CF4, even if reporters are not claiming DREs for those 
systems. However, as noted above, the requirements apply only to HC 
fuel CECs used on processes that use F2 as an input gas or 
to remote plasma cleaning processes that use NF3 as an input 
gas. We are also finalizing a related definition of ``hydrocarbon-fuel-
based combustion emissions control system (HC fuel CECS),'' which we 
have revised from the proposed ``hydrocarbon-fuel-based emissions 
control system,'' to align with the 2019 Refinement and to clarify that 
the term includes systems used on processes that have the potential to 
emit F2 or fluorinated GHGs, as recommended by commenters. 
As noted above, we have also revised the final rule from proposal to 
require these estimates from HC fuel CECS purchased and installed on or 
after January 1, 2025. We are also finalizing corresponding monitoring, 
reporting, and recordkeeping requirements (see 40 CFR 98.94(e), 40 CFR 
98.96(o), and 40 CFR 98.97(b), respectively) for facilities that use HC 
fuel CECS purchased and installed during or after 2025 to control 
emissions from tools that use either NF3 as an input gas in 
RPC processes or F2 as an input gas in any process and 
assume in equation I-9 that one or more of those systems do not form 
CF4 from F2. Under these requirements facilities 
must certify and document that the model for each of the systems that 
the facility assumes does not form CF4 from F2 
has been tested and verified to produce less than 0.1 percent 
CF4 from F2, and that each of these systems is 
installed, operated, and maintained in accordance with the directions 
of the HC fuel CECS manufacturer. The facility may perform the testing 
itself, or it may supply documentation from the HC fuel CECS 
manufacturer that supports the certification. Because the requirement 
to quantify emissions of CF4 from F2 is being 
applied only to HC fuel CECS purchased and installed on or after

[[Page 31829]]

January 1, 2025, we anticipate that most HC fuel CECS will be tested by 
the HC fuel CECS manufacturer. If the facility performs the testing, it 
is required to measure the rate of conversion from F2 to 
CF4 using a scientifically sound, industry-accepted method 
that accounts for dilution through the abatement device, such as the 
EPA DRE Protocol, adjusted to calculate the rate of conversion from 
F2 to CF4 rather than the DRE.
    The EPA is also finalizing related amendments to 40 CFR 
98.94(j)(1)(i) to require that the uptime (i.e., the fraction of time 
that abatement system is operational and maintained according to the 
site maintenance plan for abatement systems) during the stack testing 
period average at least 90 percent for uncertified HC fuel CECS. 
Following consideration of comments received, we are clarifying in the 
final rule that these provisions are limited to only those HC fuel CECS 
that were purchased and installed on or after January 1, 2025, that are 
used to control emissions from tools that use either NF3 in 
remote plasma cleaning processes or F2 as an input gas in 
any process type or sub-type, and that are not certified not to form 
CF4. See section III.G.2.a. of this preamble for additional 
information on related comments on HC fuel CECS and the EPA's response.
    Finally, the EPA is not taking final action on proposed revisions 
to the calibration requirements for abatement systems. In the 2022 Data 
Quality Improvements Proposal, the EPA proposed that a vacuum pump's 
purge flow indicators are calibrated every time a vacuum pump is 
serviced or exchanged, with the expectation that this requirement would 
require calibrations every one to six months, depending on the process. 
Following review of input provided by commenters, we are not taking 
final action on the proposed revisions. Removal of the proposed 
requirements is anticipated to reduce the potential burden on reporters 
without any large effects on data quality. Section III.G.2.a. of this 
preamble provides additional information on the comments received 
related to vacuum pump purge flow calibration and the EPA's response.
b. Revisions To Streamline and Improve Implementation for Subpart I
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
several revisions intended to streamline the calculation, monitoring, 
or reporting in specific provisions in subpart I to provide flexibility 
or increase the efficiency of data collection. The EPA is finalizing 
these changes as proposed. First, the final rule revises the 
applicability of subpart I as follows:
     Adds a second option in 40 CFR 98.91(a)(1) and (2) for 
estimating GHG emissions for semiconductor, MEMS, and LCD 
manufacturers, for comparison to the 25,000 mtCO2e per year 
emissions threshold in 40 CFR 98.2(a)(2), that is based on gas 
consumption in lieu of production capacity. The revisions include new 
equations I-1B and I-2B to multiply gas consumption by a simple set of 
emission factors, the gas GWPs, and a factor to account for heat 
transfer fluid to estimate emissions. The emission factors are included 
in new table I-2 to subpart I of part 98 and are the same as the 
emission factors for gas and process combinations for which there is no 
default in tables I-3, I-4, or I-5 to subpart I. Facilities that choose 
to use this option for their calculation method will be required to 
track annual gas consumption by GHG but are not required to apportion 
consumption by process type for the purposes of assessing rule 
applicability.
     Revises the current applicability calculation for PV 
manufacturers to revise equation I-3 and refer to new table I-2, and 
delete the phrase ``that have listed GWP values in table A-1,'' to 
increase the accuracy of the estimated emissions for determining 
applicability; and
     Updates the emission factors in table I-1 to subpart I of 
part 98 used in the current applicability calculations for MEMS and LCD 
manufacturers based on new Tier 1 emission factors in the 2019 
Refinement.
    Additional information on the EPA's revisions to applicability and 
the final emission factors is available in section III.E.2.a. of the 
preamble to the 2022 Data Quality Improvements Proposal.
    The EPA additionally proposed, and is finalizing, to revise the 
frequency and applicability of the technology assessment report 
requirements in 40 CFR 98.96(y), which applies to semiconductor 
manufacturing facilities with GHG emissions from subpart I processes 
greater than 40,000 mtCO2e per year. First, we are 
finalizing amendments to 40 CFR 98.96(y) to decrease the frequency of 
submission of the reports from every three years to every five years. 
As we noted in the preamble to the 2022 Data Quality Improvements 
Proposal, revising the frequency of submission to every five years will 
increase the likelihood that reports will include updates in technology 
rather than conclusions that technology has not changed. At the time of 
proposal, this would have moved the due date for the next technology 
assessment, from March 31, 2023, to March 31, 2025. Because the EPA is 
not implementing the revisions in this final rule until January 1, 
2025, we have revised the provision in the final rule to clarify that 
the first technology assessment report due after January 1, 2025 is due 
on March 31, 2028. Section III.G.2.b. of this preamble provides 
additional information on the comments received related to the 
frequency of submittal of the technology assessment report and the 
EPA's response.
    We are also finalizing revisions to restrict the reporting 
requirement in 40 CFR 98.96(y) to facilities that emitted greater than 
40,000 mtCO2e and produced wafer sizes greater than 150 mm 
(i.e., 200 mm or larger) during the period covered by the technology 
assessment report, as well as explicitly state that semiconductor 
manufacturing facilities that manufacture only 150 mm or smaller wafers 
are not required to prepare and submit a technology assessment report. 
The final provisions also clarify that a technology assessment report 
need not be submitted by a facility that has ceased (and has not 
resumed) semiconductor manufacturing before the last reporting year 
covered by the technology assessment report (i.e., no manufacturing at 
the facility for the entirety of the year immediately before the year 
during which the technology assessment report is due).
2. Summary of Comments and Responses on Subpart I
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart I. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart I.
a. Comments on Revisions To Improve the Quality of Data Collected for 
Subpart I
    Comment: The EPA received several comments related to the proposed 
revisions to the stack testing calculation methodology in subpart I. 
Largely, commenters objected to the EPA's proposal that ``all stacks'' 
be tested. The commenters questioned the use of the terminology ``all 
stacks'' within the proposed preamble and disagreed with the EPA's 
assumption that the number of stacks at each fab is expected to be 
small (e.g., one to two). The commenters provided input from an 
industry survey of 33 fabs, suggesting that over 250

[[Page 31830]]

stacks would require testing, as well as an additional 170 process 
stacks that do not contain F-GHGs (e.g., general fab exhausts). The 
commenters urged that adding stacks that do not have the potential to 
emit F-GHGs to the stack testing scope would add an additional $60,000 
to $200,000 per testing event and as much as $400,000 for large sites. 
The commenters requested the EPA clarify that the testing is required 
for all operating stacks or stack systems that have the potential to 
emit F-GHGs, and that the rule retain the current terminology of 
``stack system.''
    Response: Even though the EPA referred to ``all stacks'' in the 
proposal preamble, we agree that the testing is required only for all 
operating stack systems. The proposed and final regulatory text 
continue to use the term ``stack system,'' which is defined as ``one or 
more stacks that are connected by a common header or manifold, through 
which a fluorinated GHG-containing gas stream originating from one or 
more fab processes is, or has the potential to be, released to the 
atmosphere. For purposes of this subpart, stack systems do not include 
emergency vents or bypass stacks through which emissions are not 
usually vented under typical operating conditions.'' We are finalizing 
the proposed requirement that all stack systems must be tested in 
accordance with 40 CFR 98.93(i)(3)(ii).
    Comment: The EPA received comments objecting to proposed revisions 
to the technology assessment report to require use of three proposed 
calculation methods (i.e., the dominant input gas method, all-input gas 
method, and reference emission factor method) to develop utilization 
and byproduct emission factors. The commenters expressed that each of 
EPA's proposed methods fails to meet the agency's goals for consistent 
implementation of emission factors across facilities and to allow for 
comparability across the industry and in industry emission rates. 
Specifically, the commenters asserted that the dominant input gas 
method and all-input gas method violate the physical reality of 
conservation of mass for plasma etch/wafer cleaning processes when 
using multiple gases and may lead to byproduct emission factors greater 
than 1. The commenters continued that the dominant input gas method 
does not clearly define what gas would be dominant in situations where 
gases of equal or near-equal mass are used. For both of the all-input 
gas method and the dominant input gas method, the commenters criticized 
the use of a ``cap'' value of 0.8 as inconsistent with the agency's 
goal to calculate emission factors consistently with those already in 
the EPA's data set. For the all-input gas method, commenters added that 
the cap of 0.8 for individual testing does not align with the maximum 
seen within historical test data submitted by industry, but is instead 
aligned with the maximum average emission factor across all gases. 
Commenters stated that the modification to both methods may amplify or 
obfuscate technology changes by setting an artificial maximum emissions 
value.
    The commenters also stated that it is unclear how the reference 
emission factor method would be implemented. Specifically, commenters 
questioned whether 1-U or the byproduct emission factors would be held 
constant, maintaining that the method increases the difficulty in 
comparing individual tests depending on what is held constant, and 
adding that if new gases or byproducts are used or measured, the 
methodology will not have a reference emission basis to apply. 
Commenters expressed that the additional burden and complexity of 
calculating technology emission factors three different ways could be a 
disincentive to facility testing and would not improve overall 
emissions accuracy.
    The commenters requested that in lieu of the three calculation 
methods, the EPA consider use of the ``multi-gas method,'' which 
attributes all non-carbon-containing GHGs, such as SF6 and 
NF3, to the input of these non-carbon-containing GHGs and 
attributes all carbon-containing F-GHG emissions across all carbon-
based input F-GHGs. The commenters believe that the multi-gas method 
would appropriately assign emissions (especially for recipes running 
more than two gases at once), would eliminate concerns regarding 
emission factors that do not meet conservation of mass principles, and 
is not reliant on past or assumed data to calculate emission factors or 
byproduct emission factors. Commenters explained that high variability 
in single-gas emission factors is due to a variety of factors, 
including the amount or concentration of input gases, as well as plasma 
and manufacturing tool variables, and suggested that use of the multi-
gas method would generate emission factors consistent and within the 
range of the existing emission factor data, while also being able to 
accommodate new gases and changes in technology.
    Response: The EPA disagrees with the commenter's assessment of the 
three proposed emission factor methods. We also disagree that the 
proposed requirements are overly burdensome. However, following 
consideration of the comments raised, we are revising the final rule to 
require reporters to estimate emission factors using two of the three 
proposed methods (the all-input gas method and the reference emission 
factor method) and to allow reporters to submit results using an 
additional method of their choice. As noted in the preamble to the 
proposed rule, we plan to provide a spreadsheet that will automatically 
perform the calculations for the two required methods using a single 
data set entered by the reporters, minimizing burden. As explained in 
both section III.E.1.b. to the preamble to the 2022 Data Quality 
Improvements proposal and the subpart I technical support document,\12\ 
the all-input gas method is quite consistent with the historically used 
methods, differing from the historically used methods only under 
circumstances where the historically used methods are likely to yield 
unrealistic results (e.g., where CF4 is used as an input gas 
and accounts for a small fraction of the mass of all input gases, 
yielding CF4 input gas emission factors over 0.8). Of the 
three methods proposed, the reference emission factor method is 
somewhat less consistent with the historically used methods, but is 
expected to be more robust in that its results are less affected by 
changing ratios of input gases. As discussed further below, both of 
these methods are more consistent with the historical methods and less 
affected by changing input gas ratios than the method favored by the 
commenter, the multi-gas method.
---------------------------------------------------------------------------

    \12\ See document ``Technical Support for Proposed Revisions to 
Subpart I (2022),'' available in the docket for this rulemaking, 
Docket ID. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    After consideration of comments, the EPA is not taking final action 
on the proposed requirement to report emission factors calculated using 
the dominant gas method for several reasons. First, the dominant gas 
method estimates the input gas emission rate in the same way as the 
all-input gas method, making it redundant with the all-input gas method 
for calculation of input gas emission rates. Second, the dominant gas 
method estimates the byproduct emission rate by assigning all emissions 
of F-GHG byproducts to the carbon-containing F-GHG input gas accounting 
for the largest share by mass of the input gases, which is anticipated, 
as noted by commenters, to be less accurate in cases where input gases 
of equal or near-equal mass are used. Third, in the historical data 
sets submitted to the EPA, the all-input gas method was the most 
commonly used

[[Page 31831]]

method; therefore, retaining this approach rather than the dominant gas 
method will allow the EPA to more reliably compare the new data 
submitted to the historical data set. Finally, not requiring use of the 
dominant gas method will reduce burden on facilities that are required 
to submit technology assessment reports.
    As noted in the preamble to the 2022 Data Quality Improvements 
proposal, receiving results based on multiple methods will enable the 
EPA: (1) to directly compare the new emission factor data to the 
emission factor data that are already in the EPA's database and that 
were calculated using the historical method; and (2) to compare the 
results across the available emission factor calculation methods and to 
identify any systematic differences in the results of the different 
methods for each gas and process type. By identifying and quantifying 
systematic differences in the results of the different methods, we will 
be better able to distinguish these differences from differences 
attributable to technology changes. Knowledge of these systematic 
differences will also be useful in the event that we ultimately require 
facilities to submit emission factors using one method only, 
particularly if that method is not closely related to one of the 
methods used historically. We will also be able to evaluate how much 
the results of each method vary for each gas and process type; high 
variability may indicate that the results of a method are being 
affected by varying input gas proportions rather than differences in 
gas behavior. On the other hand, extremely low variability may also 
indicate that a method is affected by input gas proportions. For 
example, if the all-input-gas method yields a large number of input gas 
emission factors equal to 0.8, the maximum allowed value for input gas 
emission factors under this method, this implies that some of the 
emissions being attributed to the input gas are actually being 
generated as byproducts from other input gases that are collectively 
more voluminous, conditions under which the reference emission factor 
method may yield the most reliable results. Ultimately, these analyses 
will enable us to more accurately characterize emissions from 
semiconductor manufacturing by selecting the most robust emission 
factor data for updating the default emission factors in tables I-3 and 
I-4. Note that the EPA would update the default emission factors using 
the rulemaking process, providing an opportunity for industry to 
comment on the data and methodology used to develop any proposed 
factors.
    Regarding the comment that the proposed rule did not clarify how 
the reference emission factor would be implemented, including whether 
the 1-U or by-product emission factors would be adjusted, the proposed 
rule made it clear that both the 1-U and byproduct emission factors 
would be adjusted where the emitted gas was also an input gas. The 
preamble to the proposed rule stated, ``the reference emission factor 
method calculates emissions using the 1-U and the BEFs [by-product 
emission factors] that are observed in single gas recipes and then 
adjusts both factors based on the ratio between the emissions 
calculated based on the factors and the emissions actually observed in 
the multi-gas process. This approach uses all the information available 
on utilization and by-product generation rates from single-gas recipes 
while avoiding assumptions about which of these are changing in the 
multi-gas recipe'' (87 FR 36947). The proposed equations I-31A (for 1-U 
factors, finalized as equation I-30A) and I-31B (for by-product 
factors, finalized as equation I-30B) showed this in mathematical terms 
and also showed how the method would apply where more than two input 
gases were used. The proposed rule also clearly indicated that where a 
by-product gas was not also an input gas, proposed equation I-30B 
(finalized as equation I-29B) was to be used. Equation I-29B is the 
equation used in the all-input-gas method as well as the reference 
emission factor method for by-products that are not also input gases. 
Equation I-29B would apply to newly observed as well as previously 
observed by-product gases that were not also input gases.
    This leaves only the situation where an input gas is used in a 
process type for the first time along with other input gases. While we 
expect that this situation will be rare, we agree that it should be 
addressed. We are clarifying in the final rule that where an input gas 
is used in a process type with other input gases and there is no 1-U 
factor for that input gas in table I-19 or I-20, as applicable, the 
Reference Emission Factor Method will not be used to estimate the 
emission factors for that process.
    We are not specifying the multi-gas method as the sole method for 
calculating emission factors submitted in the technology assessment 
report. As noted in the proposed rule, one of the EPA's goals in 
collecting emission factor data through the technology assessment 
report is to better understand how emission factors may be changing as 
a result of technological changes in the semiconductor industry, and 
whether the changes to the emission factors may justify further data 
collection to comprehensively update the default emission factors in 
tables I-3 and I-4. To meet this goal, the emission factors submitted 
in the technology assessment reports should be calculated using methods 
that are similar to the methods used to calculate the emission factors 
already in the EPA's database; otherwise, differences attributable to 
differences in calculation methods may amplify or obscure differences 
attributable to technology changes. The multi-gas method assigns 
emissions of all carbon-containing F-GHGs to all carbon-containing F-
GHG input gases, regardless of species, yielding input gas emission 
factors that are equal to byproduct gas formation factors for each 
emitted F-GHG. These input gas and byproduct gas emission factors are 
significantly different from the input gas and byproduct gas emission 
factors yielded by the historically used methods, making it difficult 
to discern the impact of technology changes as opposed to calculation 
method changes on the emission factors. In addition, our analysis 
indicated that the multi-gas method results are highly sensitive to the 
ratios of the masses of input gases fed into the process, which appears 
likely to affect the robustness and reliability of emission factors 
calculated using that method.\13\ For these reasons, we have concluded 
that it would not be appropriate to require submission of emission 
factors using only the multi-gas method.
---------------------------------------------------------------------------

    \13\ Id. The EPA has included in the docket a memo and 
spreadsheet showing the results of the different emission factor 
calculation methods using the same data (see Docket ID. No. EPA-HQ-
OAR-2019-0424-0142, memorandum and attachment 3 Excel spreadsheet).
---------------------------------------------------------------------------

    However, we are providing an option in the final rule for reporters 
to use, in addition to the required all-input gas method and the 
reference emission factor method, an alternative method of their choice 
to calculate and report updated utilization or byproduct formation 
rates based on the collected data. Reporters will therefore have the 
opportunity to provide emission factor data that are calculated using 
the multi-gas method or other methodologies, provided the reporter 
provides a complete, mathematical description of the alternative 
calculation method and labels the data calculated using that method 
consistent with the requirements for the all-input gas method and the 
reference emission factor method. Submitting emission factors 
calculated using the multi-gas

[[Page 31832]]

method along with the other two methods would allow us to compare the 
results of the multi-gas method to the results of the other two (one of 
which is very similar to the primary historically used method) and to 
identify any systematic differences. As noted above, by identifying and 
quantifying systematic differences in the results of the different 
methods, we will be better able to distinguish these differences from 
differences attributable to technology changes. We may also be able to 
relate the results of the historical methods to the results of methods 
that differ from those used historically. Receiving emission factors 
calculated using three methods would also allow us to better assess the 
robustness and reliability of the emission factors calculated using all 
three methods, e.g., by seeing which methods yield highly variable 
emission factors within each input gas-process type combination. 
Because the final rule does not require reporters to submit emission 
factors calculated using an alternative methodology, the requirement to 
provide a complete, mathematical description of the alternative 
calculation method used is not anticipated to add significant burden.
    Comment: Commenters supported the proposal to remove BEFs for 
C4F6 and C5F8 and the 
decision to not add COF2 and C2F4, as 
byproduct emissions of them account for <<0.001% of overall GHG 
emissions from semiconductor manufacturing operations. One commenter 
also requested the EPA clarify that carbon-containing byproduct 
emission factors are zero when calculating emissions from non-carbon 
containing input gases (SF6, NF3, F2, 
or other non-carbon input gases) and when the film being etched or 
cleaned does not contain carbon, as this would align the EPA final rule 
with the 2019 Refinement.
    Response: The EPA is finalizing the rule as proposed to remove the 
BEFs for C4F6 and C5F8. The 
EPA is also not adding BEFs for COF2 or 
C2F4. For non-carbon containing input gases used 
in cleaning processes, we proposed to set carbon-containing byproduct 
emission factors to zero when the combination of input gas and chamber 
cleaning process sub-type is never used to clean chamber walls on 
manufacturing tools that process carbon-containing films during the 
year (e.g., when NF3 is used in remote plasma cleaning 
processes to only clean chambers that never process carbon-containing 
films during the year). We agree with the commenter that non-carbon-
containing input gases used in etching processes are similarly not 
expected to give rise to carbon-containing byproducts if neither the 
input gases nor the films being etched contain carbon. We are therefore 
finalizing an expanded version of the proposed provision, setting 
carbon-containing byproduct emission factors to zero for etching and 
wafer cleaning processes as well as chamber-cleaning processes when 
these conditions are met. The revisions align the rule requirements 
with the 2019 Refinement.
    Comment: Commenters expressed several concerns regarding the EPA's 
proposed revisions to the conditions under which the default DRE may be 
claimed. One commenter requested the EPA remove the requirement to 
provide supporting documentation for all abatement units using 
certified default or lower than default DREs. The commenter also 
requested the EPA clarify that reporters are not required to maintain 
supporting documentation on abatement units for which a DRE is not 
being claimed.
    Commenters also contended that the existing language in subpart I 
is sufficient to ensure proper point-of-use (POU) device performance 
while being consistent with the 2019 Refinement, and the requirement to 
provide supporting documentation of manufacturer certified POU DREs, 
including testing method, is burdensome and may be unachievable, 
especially for older abatement units. One commenter expressed concern 
that the proposed increase in certification and documentation 
requirements beyond existing POU operational requirements will dissuade 
semiconductor companies from accounting for DREs from installed POU, 
resulting in an over-estimate of emissions from the semiconductor 
industry. The commenter also stated that adding operational elements of 
fuel and oxidizer settings, fuel gas flows and pressures, fuel 
calorific values, and water quality, flow, and pressures to the POU DRE 
requirements are outside the manufacturer-specified requirements for 
emissions control and are not necessary to ensure accurate POU DREs. 
Commenters stated that abatement equipment installed across the 
industry does not have manufacturer specifications for all listed 
parameters, or the capability to track all listed parameters. 
Commenters concluded that these and other POU default DRE certification 
and documentation requirements go above and beyond the 2019 Refinement 
and will make it more difficult for U.S. reporters to take credit for 
installed and future emissions control devices, resulting in a less 
accurate, overestimated GHG emissions inventory. One commenter 
supported applying the requirements only to equipment purchased after 
the reporting rule becomes effective. The commenter stated that 
verification testing would be especially burdensome; the commenter 
estimated testing to take approximately 20 weeks per chemistry and 
stated it could take up to 2+ years for individual vendors to have 
required documentation. The commenter also expressed concern that the 
proposed requirements could have cascading impacts to facility 
manufacturing and operating permits based on state implementation of 
the Tailoring Rule, which typically rely on GHGRP protocols. Commenters 
supported aligning the emission control device operational requirements 
for default POU DREs with the following 2019 Refinement language: ``. . 
. obtain a certification by the emissions control system manufacturers 
that their emissions control systems are capable of removing a 
particular gas to at least the default DRE in the worst-case flow 
conditions, as defined by each reporting site.''
    The commenter also requested the EPA include language supporting 
full uptime for emission control devices interlocked with manufacturing 
tools or with abatement redundancy. The commenter supported 2019 
Refinement language that: ``Inventory compilers should also note that 
UT [uptime] may be set to one (1) if suitable backup emissions control 
equipment or interlocking with the process tool is implemented for each 
emissions control system. Thus, using interlocked process tools or 
backup emissions control systems reduces uncertainty by eliminating the 
need to estimate UT for the reporting facility.'' The commenter 
contended that such language will drive further use of manufacturing 
tool interlocks or emission control system redundancy while having the 
added benefit of simplifying uptime tracking of individual POU.
    Response: The EPA is clarifying in this response that reporters are 
not required to maintain documentation of the DRE on abatement units 
for which a DRE is not being claimed. However, no regulatory changes 
are needed to reflect this clarification. For abatement units for which 
a DRE is being claimed, reporters are still required to provide 
certification that the abatement systems for which emissions are being 
reported were specifically designed for fluorinated GHG or 
N2O abatement, as applicable, and support the certification 
by providing abatement system supplier documentation stating that the 
system was designed for fluorinated GHG or N2O abatement. 
The facility must certify

[[Page 31833]]

that the DRE provided by the abatement system manufacturer is greater 
than or equal to the DRE claimed (either the default, if the certified 
DRE is greater than or equal to the default, or the manufacturer-
verified DRE itself, if the certified DRE is lower than the default 
DRE). To use the default or lower manufacturer-verified destruction or 
removal efficiency values, operation of the abatement system must be 
within the manufacturer's specifications. It was not the EPA's intent 
to require that certified abatement systems that operate within the 
manufacturer's specifications must meet all the operational parameters 
listed, and we are revising the final rule at 40 CFR 98.96(q)(2) to add 
``which may include, for example,'' to clarify that, in order to use 
the default or lower manufacturer-verified destruction or removal 
efficiency values, operation of the abatement system must be within 
those manufacturer's specifications that apply for the certification.
    In the final rule, the EPA is maintaining the current certification 
and documentation requirements for older POU abatement devices, 
although the certification must contain a manufacturer-verified DRE 
value that is equal to or higher than the default in order to claim the 
default DRE; facilities are allowed to claim a lower manufacturer-
verified value if the provided certified DRE is lower than the default. 
The EPA concurs that some older POU abatement systems may not have full 
documentation from the manufacturer of the test methods used and 
whether testing was conducted under worst-case flow conditions; 
however, we believe this documentation should be available for most 
newer abatement systems. As a result, reporters with the older POU 
abatement devices will not have any additional documentation 
requirements beyond those currently in place, except to provide the 
certified DRE. Following a review of annual reports submitted under 
subpart I, we determined that facilities have historically provided 
manufacturer-verified DRE values for all abatement systems for which 
emission reductions have been claimed. Therefore, we have determined 
that these final requirements are reasonable. The EPA is finalizing the 
new documentation requirements for POU abatement devices purchased on 
or after January 1, 2025 under 40 CFR 98.94(f)(3)(i) and (ii), these 
additional requirements include that the manufacturer-verified DREs 
reflect that the abatement system has been tested by the manufacturer 
using a scientifically sound, industry-accepted measurement methodology 
that accounts for dilution through the abatement system, such as the 
EPA DRE Protocol (EPA 430-R-10-003), and verified to meet (or exceed) 
the default destruction or removal efficiency for the fluorinated GHG 
or N2O under worst-case flow conditions. Since manufacturers 
routinely conduct DRE testing and are familiar with the protocols of 
EPA 430-R-10-003, this information would be readily available for 
abatement systems purchased in calendar year 2025 or later. Further, 
these final rule requirements will be implemented for reports prepared 
for RY2025 and submitted March 31, 2026, providing adequate time for 
reporters to acquire documentation.
    The EPA agrees with the recommendation to align the rule with the 
2019 Refinement with respect to the uptime factor for interlocked tools 
and abatement systems and is making this change in the final rule. The 
use of interlocked tools is already accounted for in the current rule 
in the definition of terms ``UTijp'' and ``UTpf'' 
in equations I-15 and I-23 (the total time in minutes per year in which 
the abatement system has at least one associated tool in operation), 
which state that ``[i]f you have tools that are idle with no gas flow 
through the tool for part of the year, you may calculate total tool 
time using the actual time that gas is flowing through the tool.'' 
However, to clarify and simplify the calculation of uptime where 
interlocked tools are used, the EPA is revising the definition of the 
term ``UTij'' in equation I-15 to say that if all the 
abatement systems for the relevant input gas and process type are 
interlocked with all the tools feeding them, the uptime may be set to 
one (1). The revised text specifies that ``all'' tools and abatement 
systems for the relevant input gas and process sub-type or type are 
interlocked because the numerator and denominator of the uptime 
calculation in equations I-15 and I-23 are separately summed across 
abatement systems for input gas ``i'' and process sub-type or type 
``j.'' Similar changes are made for the same reasons in the definition 
of ``UTf'' in equation I-23. With the use of an interlock 
between the process tool and abatement device, the process tool should 
never be operating when the abatement device is not operating.
    The current rule also accounts for the use of redundant abatement 
systems. Section 98.94(f)(4)(vi) currently states, ``If your fab uses 
redundant abatement systems, you may account for the total abatement 
system uptime (that is, the time that at least one abatement system is 
in operational mode) calculated for a specific exhaust stream during 
the reporting year.'' This provision achieves nearly the same objective 
as suggested by the commenters. To clarify this point, the EPA is 
revising the definition of the terms ``Tdijp'' in equation 
I-15 and ``Tdpf'' in equation I-23 to reference the 
provision in 40 CFR 98.94(f)(4)(vi) when accounting for uptime when 
redundant abatement systems are used.
    Comment: Commenters objected to the EPA's proposed requirements to 
include a calculation methodology to estimate emissions of 
CF4 produced in hydrocarbon-fuel based combustion emissions 
control systems (HC fuel CECS) that are not certified not to generate 
CF4. The commenters claimed that the CF4 
byproduct emissions from HC fuel CEC abatement of F2 gas 
(from etch or remote plasma chamber cleaning processes) are based on 
limited and unverified data. Specifically, the commenters expressed 
concern that the values documented within the 2019 Refinement and 
referenced within the proposal are based on a single, confidential data 
set from one abatement supplier. One commenter stated that developing 
regulatory language around this single, unverified data set does not 
accurately represent the CF4 byproduct emissions from the 
uses or generation of F2 and may deliver an advantage to the 
single emissions control system supplier that provided the data.
    The commenters also listed the following concerns with the 
information provided within the 2019 Refinement and the proposed rule 
supporting documentation upon which the CF4 byproduct 
(ABCF4,F2 and BF2,NF3) is based:
     The F2 emission values presented in ``Influence 
of CH4-F2 mixing on CF4 byproduct 
formation in the combustive abatement of F2'' by Gray & Banu 
(2018) are based on testing conducted in a lab under conditions that 
are not found in actual semiconductor abatement installations. Test 
methods do not appear to adhere to those specified in industry standard 
test methods or the EPA DRE Protocol. F2 results are 
measured from a device, the MST Satellite XT, designed to provide 
``nominal'' F2 concentrations meant for health and safety 
risk management and not for environmental emissions measurement.
     ``FTIR spectrometers measure scrubber abatement 
efficiencies'' by Li, et al. (2002) and ``Thermochemical and Chemical 
Kinetic Data for Fluorinated Hydrocarbons'' by Burgess, et al. (1996) 
provide anecdotal and hypothetical emission pathways for the combustion 
of fluorinated gases, but do not confirm

[[Page 31834]]

reliable and peer reviewed CF4 emission results from current 
semiconductor manufacturing use or generation of F2.
     EPA references a single, confidential data set from 
Edwards, Ltd. (2018) upon which numerical ABCF4,F2 and 
BF2,NF3 values are based. This single data set of 15 
measurements refers to an RPC NF3 to F2 emission 
value based on mass balance. The commenter opposed using the data 
provided by Edwards confidentially without the ability to review the 
underlying data and experimental procedure of the 15 measurements upon 
which the RPC NF3 to F2 emission factor was 
based. Mass balance has shown to be a highly conservative method in 
estimating emission factors and this confidential data set lacks 
visibility into repeatability, experimental design, and semiconductor 
process applicability.
    The commenters further contended that the requirement to calculate 
CF4 emissions from HC fuel CECS abatement of F2, 
based on equation I-9 if the HC fuel CECS is not certified to not 
convert F2 at less than 0.1%, adds complexity to 
apportioning RPC NF3 and F2 to both <0.1% 
certified and uncertified HC fuel CECS and will require time and cost 
investments which are not justified by data. One commenter added that 
this could disincentivize the use of low emission NF3 cleans 
or potentially slow implementation of F2 processes with 
zero-GWP potential due to the requirement to report CF4 BEF 
generation with tools with POU abatement. Another commenter added that 
this requirement appears to apply to all relevant HC fuel CECS 
regardless of whether a default or measured DRE is claimed for the 
abatement device. The commenter stated that if HC fuel CECS abatement 
suppliers and device manufacturers are not able to provide the required 
certification to exempt systems from this added emission, for every 
kilogram of RPC NF3 used, CO2e emissions out of 
the HC fuel CECS will increase more than 600% for 200 mm and more than 
400% for 300 mm processes. Commenters added that this jump in 
CF4 emissions will result in a time series inconsistency for 
semiconductor industry greenhouse gas reporting.
    One commenter also stated that, if EPA maintains this requirement, 
it is unclear if equation I-9 applies in addition to or in place of 
existing CF4 byproduct emission factors. The commenter 
requested that CF4 emissions from the HC fuel CECS abatement 
of F2, as calculated by equation I-9, are applied instead 
of, not in addition to, default CF4 BEFs for RPC 
NF3. Commenters requested the removal of equation I-9 and 
associated ABCF4,F2 and BF2,NF3 data elements; 
one commenter added that an alternative would be to make changes to HC 
fuel CECS requirements to remove confusion and double counting of 
emissions.
    Response: The EPA disagrees with the commenter after a thorough 
review of the issue, as documented in detail in a memorandum in the 
docket for the final rulemaking.\14\ The analysis conducted for the EPA 
demonstrated that: (1) the formation of CF4 by reaction of 
CH4 and F2 in POU combustion systems is 
thermodynamically favored and that there is no question that 
CF4 emissions can be observed if mixing of CH4 
and F2 is allowed to occur; (2) that a revised 
BF2,NF3 default emission factor of 0.5 is well supported by 
scientific peer-reviewed evidence to describe the formation of 
F2 from NF3-based RPC processes; (3) that the 
proposed default value for ABCF4,F2 of 0.116, describing the 
rate of formation of CF4 from F2, is well 
supported by experimental evidence under conditions that are 
representative of the designs and use of commercially available POU 
emissions control systems in production conditions; (4) that there is 
strong prima facie evidence of the formation of CF4 from 
within POU emissions control systems during the production of 
semiconductor devices; and (5) that not reporting such CF4 
emissions could lead to a significant underestimation of GHG emissions 
from semiconductor manufacturing facilities.
---------------------------------------------------------------------------

    \14\ Memorandum from Sebastien Raoux to U.S. EPA. 
``CF4 byproduct formation from the combustion of 
CH4 and F2 in Point of Use emissions control 
systems in the electronics industry.'' Prepared for the U.S. EPA. 
May 2023, available in the docket for this rulemaking, Docket ID. 
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Based on the evidence documented in the memorandum, the EPA is 
finalizing as proposed the requirement that the electronic 
manufacturers estimate and report CF4 byproduct emissions 
from hydrocarbon-fuel-based POU emissions control systems that abate 
F2 processes or NF3-based RPC processes.
    The EPA is also requiring that reporters estimate CF4 
emissions from all POU abatement devices that are not certified not to 
produce CF4, even if they are not claiming a DRE from those 
devices, because the CF4 emissions from HC fuel combustion 
in the abatement of F2 or F-GHG is a separate issue from 
whether or not a DRE is claimed for the same devices. The EPA disagrees 
that the rule is adding unnecessary complexity to apportion RPC 
NF3 and F2 between POU abatement systems that are 
certified not to convert F2 to CF4 and those that 
are not certified. Reporters will use tool counts in this case rather 
than the usual gas apportioning model. This should be straightforward 
because it requires the reporters to: (1) count the total number of 
tools running the process type of interest (either RPC NF3 
or F2 in any process type); (2) count the number of tools 
running that process type that are equipped with HC fuel CECs that are 
not certified not to form CF4; and (3) divide (2) by (1).
    The EPA is revising the final rule to require that reporters must 
only provide estimates of CF4 emissions from HC fuel CECS 
purchased and installed on or after January 1, 2025. We recognize that 
applying the testing, certification, and emissions estimation 
requirements to older equipment would have expanded the set of 
equipment for which testing would need to be performed and/or emissions 
would need to be estimated, which may have posed logistical challenges, 
particularly for older equipment that may no longer be manufactured. 
Making the requirements applicable only to HC fuel CECs purchased and 
installed on or after January 1, 2025 ensures that abatement system 
manufacturers and/or electronics manufacturers can test the equipment 
and measure its CF4 generation rate from F2 by 
March 31, 2026, by which time facilities must either certify that the 
HC fuel CECS do not generate CF4 or quantify CF4 
emissions from the HC fuel CECS.
    The EPA recognizes that the new requirement to report 
CF4 emissions from HC fuel CECS could lead to a time series 
inconsistency in reported emissions. However, such an inconsistency is 
not in conflict with the overall purpose of the GHGRP to accurately 
estimate GHG emissions. Nor would it be unique to the electronics 
industry, because other GHGRP subparts have been revised in ways that 
altered the time series of the emissions as new source types were added 
or more accurate methods were adopted. For example, in 2015, subpart W 
was updated to include a new source, completions and workovers of oil 
wells with hydraulic fracturing, in the existing Onshore Petroleum and 
Natural Gas Production segment and also added two entirely new 
segments, the Onshore Petroleum and Natural Gas Gathering and Boosting 
and Onshore Natural Gas Transmission Pipelines segments. Such changes 
in reported emissions are often documented in the public data, 
including in the EPA's sector profiles.
    The EPA is clarifying in this response to comment that equation I-9 
is in addition to, rather than in place of, CF4 byproduct 
factors for RPC NF3, because the CF4 byproduct 
factors for RPC NF3

[[Page 31835]]

represent emissions from the process before abatement, and these 
emissions were measured without abatement equipment running.
    Comment: One commenter supported using the term ``hydrocarbon-fuel-
based combustion emissions control systems'' (HC fuel CECS) because it 
aligns with the nomenclature within 2019 Refinement rather than the 
less used ``hydrocarbon-fueled abatement systems'' or other terms. The 
commenter explained that semiconductor facilities widely implement 
large, facility-level volatile organic compound abatement devices to 
eliminate and control criteria volatile and non-volatile organic 
compounds, with no expectation of fluorinated greenhouse gas emissions. 
The commenter expressed concern that the broad definition of HC fuel 
CECS may be interpreted to include all hydrocarbon-based fuel control 
systems, not just tool-level POU abatement. The commenter added that, 
although not currently implemented, future facility-level F-GHG 
abatement systems could be incorrectly included in the scope of 
equation I-9 as it is written. The commenter requested that all 
emissions control systems language is updated to be consistent. The 
commenter also specifically requested the definition of ``hydrocarbon-
fuel-based combustion emission control systems'' be tailored to specify 
HC fuel CECS connected to manufacturing tools, and include the 
following language: ``and have the potential to emit fluorinated 
greenhouse gases.''
    Response: The EPA agrees with the commenter and has revised the 
proposed language to include the term, ``hydrocarbon-fuel-based 
combustion emissions control systems'' (HC fuel CECS) to align with the 
nomenclature within 2019 Refinement. The EPA is also clarifying in the 
final rule that these requirements apply only to equipment that is 
connected to manufacturing tools that have the potential to emit 
F2 or F-GHGs. It is important to include emissions of 
F2 as well as F-GHGs since it is F2 that may 
combine with hydrocarbon fuels to generate CF4 emissions. 
These changes include revising ``hydrocarbon fuel-based emissions 
control systems'' to ``HC fuel CECS'' in the terms 
``EABCF4,'' aF2,j,'' ``UTF2,j,'' 
``ABCF4,F2,'' ``aNF3,RPC,'' ``and 
``UTNF3,RPC,F2'' defined in equation I-9.
    Comment: One commenter requested the EPA specify that HC fuel CECS 
uptime during stack testing is ``representative of the emissions 
stream'' and the EPA specify that HC fuel CECS uptime during stack 
testing applies to RPC NF3 or input F2 processes 
only. The commenter questioned the EPA's proposed requirement that the 
uptime during the stack testing period must average at least 90 percent 
for uncertified hydrocarbon-fueled emissions control systems. The 
commenters asserted that uptime tracking for uncertified abatement 
devices is excessive, goes beyond the 2019 Refinement requirements, and 
does not improve the accuracy of emissions estimates. The commenter 
requested language to limit this requirement to ``at least 90% uptime 
of NF3 remote plasma clean HC fuel CECS devices that are not 
certified to not form CF4 during the test.'' The commenter 
also requested EPA clarify that equation I-9 does not apply in addition 
to stack testing requirements. The commenter requested that 
CF4 emissions from the HC fuel CECS abatement of 
F2, as calculated by equation I-9, be specifically exempted 
from the stack testing method as it would double count CF4 
emissions.
    Response: The EPA agrees with the commenter that it would be 
helpful to clarify of the applicability of the 90-percent uptime 
requirement for HC fuel CECS. The EPA is revising the rule language at 
40 CFR 98.94(j)(1) to further limit the HC fuel CECS 90-percent uptime 
requirement to systems that were purchased and installed on or after 
January 1, 2025 and that are used to control emissions from tools that 
use either NF3 in remote plasma cleaning processes or 
F2 as an input gas in any process type or sub-type. Either 
of these input gas-process type combinations may exhaust F2 
into HC fuel CECS, potentially leading to the formation of 
CF4. The qualification ``that are not certified not to form 
CF4'' is being finalized as proposed.
    Regarding the commenters' concerns related to the uptime tracking 
requirements for uncertified abatement devices during stack testing, we 
reiterate that the uptime tracking requirement during stack testing is 
for hydrocarbon-fueled abatement devices that are not certified to not 
form CF4, because these reporters still need to account for 
CF4 emissions even if not accounting the abatement device's 
F-GHG DRE.
    The EPA is also clarifying in this response that equation I-9 is 
not in addition to stack test calculations. The emissions from HC fuel 
CECS, should they occur, will be captured by the stack testing 
measurements. Because equation I-9 is not included in or referenced by 
the stack testing section, the regulatory text in 40 CFR 98.93(i) as 
currently drafted does not need any additional revision. However, the 
header paragraph 40 CFR 98.93(a) has been revised to clarify that 
paragraph (a)(7), which includes equation I-9, is one of the paragraphs 
used to calculate emissions based on default gas utilization rates and 
byproduct formations rates.
    Comment: One commenter objected to the EPA's proposed calibration 
requirements for abatement systems, specifically for vacuum pump purge 
systems. The commenter urged that this would have significant impacts 
on the semiconductor industry and would drive a major increase in pump 
replacement and tool downtime. The commenter explained that POU 
abatement devices and their connected vacuum pumps are separate 
systems, and while physically connected, POU maintenance and pump 
replacement schedules are independent of one another. Further, the 
commenter asserted that pump purge flow calibration is technically and 
operationally infeasible for device manufacturers to perform. The 
commenter explained that purge flow indicators are factory calibrated 
and are part of the pump installation and commissioning; if there is a 
flow indicator failure, the vacuum pump is replaced with a factory-
calibrated pump. The commenter stated that pump maintenance and repair 
is not typically performed at the manufacturing tool and requires pump 
disconnection and physical removal, and thus pumps are often repaired 
off-site. The commenter stressed that pump manufacturers do not provide 
recommendations or specifications for re-calibration of these pumps. 
The commenter added that there is no pump redundancy installed on a 
tool, and to check the calibration and potentially replace the flow 
transducer, the vacuum pump must be shutdown to safely work on it. The 
commenter noted that any replacement of the pump would require a tool 
shutdown and therefore 12 to 48 hours of downtime for manufacturing 
requalification.
    The commenter stated that pumps remain continually in service on 
the order of years and asserted that pump vendors indicate that pumps 
can remain in service for many years without requiring calibration of 
the pump purge. The commenter provided that pump changes and 
refurbishment costs can be over $5,000 per occurrence and noted that 
pump repair or calibration activities can require significant 
coordination with factory and site operations due to the highly 
specialized equipment and resources needed. The commenter estimated 
that semiconductor manufacturing sites can have 2,000+ POU abatement 
devices as well as 4,000+ vacuum pumps in a high-volume-manufacturing 
site. The

[[Page 31836]]

commenter subsequently estimated that the EPA's proposed revisions 
could result in pump downtime, process equipment tool downtime, and 
maintenance costs to the U.S. semiconductor industry of about $40 
million annually.
    The commenter also stated that they believe the existing 
performance certification of POU emissions control devices based on 
high flow conditions are highly protective of POU system reliability. 
The commenter reiterated that high flow POU certification is based on 
maximum device flows, which, for multi-chamber tools, includes all 
chambers running at once. The commenter urged that significant 
variations in pump purge flows are unlikely and the magnitude of these 
variations would be a small component of overall POU flow volumes. As 
such, the commenter urged that pump purge flows are not necessary to 
calibrate after initial pump commissioning.
    Response: The EPA agrees with the commenter that calibration of 
N2 purge flows is normally done during pump service or 
maintenance, when the pumps are typically: (1) disconnected from the 
process tool; (2) replaced by a new or refurbished pump; and (3) 
brought to a ``service center'' for refurbishment (sometimes on-site, 
sometimes off-site). The EPA also concurs with commenters that 
requiring N2 pump purge calibration could be disruptive if 
done outside of ``normal'' service periods. Consequently, the EPA 
proposed to require that pump purge flow indicators be calibrated 
``each time a vacuum pump is serviced or exchanged'' rather than more 
frequently. The anticipated frequency of calibration mentioned in the 
preamble, every six months, was intended to be descriptive rather than 
prescriptive. Thus, the EPA does not believe that the proposed 
requirement would have the large economic impacts cited by the 
commenter. Nevertheless, because it appears that pumps are typically 
factory calibrated when commissioned and are replaced with factory-
calibrated pumps when the flow indicator fails, a calibration 
requirement is not required. Therefore, the EPA is not taking final 
action on the proposed calibration requirement.
b. Comments on Revisions To Streamline and Improve Implementation for 
Subpart I
    Comment: One commenter supported finalizing the amendment to 40 CFR 
98.96(y) decreasing the frequency of submission of technology 
assessment reports, before the due date for the next technology 
assessment report.
    Response: The EPA acknowledges the commenter's support and is 
finalizing revisions to 40 CFR 98.96(y) to decrease the frequency of 
submission of technology assessment reporters to every 5 years, as 
proposed. However, because the EPA is not implementing the final 
revisions until January 1, 2025 (see section V. of this preamble), we 
have revised the provision to clarify that the first technology 
assessment report due after January 1, 2025 is due on March 31, 2028. 
Subsequent reports must be submitted every 5 years no later than March 
31 of the year in which it is due.

H. Subpart N--Glass Production

    We are finalizing several amendments to subpart N of part 98 (Glass 
Production) as proposed. The EPA received only supportive comments for 
the proposed revisions to subpart N. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart N. We 
are also finalizing as proposed related confidentiality determinations 
for data elements resulting from the revisions to subpart N, as 
described in section VI. of this preamble.
    The EPA is finalizing two revisions to the recordkeeping and 
reporting requirements of subpart N of part 98 (Glass Production) as 
proposed in the 2022 Data Quality Improvement Proposal. The revisions 
apply to both CEMS and non-CEMS reporters and require that facilities 
report and maintain records of annual glass production by glass type 
(e.g., container, flat glass, fiber glass, specialty glass). 
Specifically, the final amendments revise (1) 40 CFR 98.146(a)(2) and 
(b)(3) to require the annual quantity of glass produced in tons, by 
glass type, from each continuous glass melting furnace and from all 
furnaces combined; and (2) 40 CFR 98.147(a)(1) and (b)(1), to add that 
records must also be kept on the basis of glass type. Differences in 
the composition profile of raw materials, use of recycled material, and 
other factors lead to differences in emissions from the production of 
different glass types. Collecting data on the annual quantities of 
glass produced by type will improve the EPA's understanding of 
emissions variations and industry trends, and improve verification for 
the GHGRP, as well as provide useful information to improve analysis of 
this sector in the Inventory. The EPA is also finalizing revisions to 
the recordkeeping and reporting requirements of subpart N as proposed 
in the 2023 Supplemental Proposal. The final revisions add reporting 
provisions at 40 CFR 98.146(a)(3) and (b)(4) to require the annual 
quantity (in tons), by glass type (e.g., container, flat glass, fiber 
glass, or specialty glass), of cullet charged to each continuous glass 
melting furnace and in all furnaces combined, and revises 40 CFR 
98.146(b)(9) to require the number of times in the reporting year that 
missing data procedures were used to measure monthly quantities of 
cullet used. The final revisions also add recordkeeping provisions to 
40 CFR 98.147(a)(3) and (b)(3) to require the monthly quantity of 
cullet (in tons) charged to each continuous glass melting furnace by 
product type (e.g., container, flat glass, fiber glass, or specialty 
glass). Differences in the quantities of cullet used in the production 
of different glass types can lead to variations in emissions, and, due 
to lower melting temperatures, can reduce the amount of energy and 
combustion required to produce glass. As such, the annual quantities of 
cullet used will further improve the EPA's understanding of variations 
and differences in emissions estimates, industry trends, and 
verification, as well as improve analysis for the Inventory. Additional 
rationale for these amendments is available in the preamble to the 2022 
Data Quality Improvements Proposal and 2023 Supplemental Proposal.

I. Subpart P--Hydrogen Production

    We are finalizing several amendments to subpart P of part 98 
(Hydrogen Production) as proposed. In some cases, we are finalizing the 
proposed amendments with revisions. In other cases, we are not taking 
final action on the proposed amendments. Section III.I.1. of this 
preamble discusses the final revisions to subpart P. The EPA received 
several comments on the proposed subpart P revisions which are 
discussed in section III.I.2. of this preamble. We are also finalizing 
related confidentiality determinations for data elements resulting from 
the revisions to subpart P, as described in section VI. of this 
preamble.
1. Summary of Final Amendments to Subpart P
    This section summarizes the final amendments to subpart P. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other final 
revisions to 40 CFR part 98, subpart P can be found in this

[[Page 31837]]

section and section III.I.2. of this preamble. Additional rationale for 
these amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart P
    In the 2023 Supplemental Proposal, the EPA proposed several 
amendments to subpart P of part 98 to expand and clarify the source 
category definition. First, to increase the GHGRP's coverage of 
facilities in the hydrogen production sector, we are amending, as 
proposed, the source category definition in 40 CFR 98.160 to include 
all facilities that produce hydrogen gas regardless of whether the 
hydrogen gas is sold. The final revisions will address potential gaps 
in applicability and reporting, allowing the EPA to better understand 
and track emissions from facilities that do not sell hydrogen gas to 
other entities. As proposed, these amendments categorically exempt any 
process unit for which emissions are currently reported under another 
subpart of part 98, including, but not necessarily limited to, ammonia 
production units that report emissions under subpart G of part 98 
(Ammonia Manufacturing), catalytic reforming units located at petroleum 
refineries that produce hydrogen as a byproduct for which emissions are 
reported under subpart Y of part 98 (Petroleum Refineries), and 
petrochemical production units that report emissions under subpart X of 
part 98 (Petrochemical Production). As proposed, we are also exempting 
process units that only separate out diatomic hydrogen from a gaseous 
mixture and are not associated with a unit that produces diatomic 
hydrogen created by transformation of feedstocks.
    The EPA is also amending the source category definition at 40 CFR 
98.160 as proposed to clarify that stationary combustion sources that 
are part of the hydrogen production unit (e.g., reforming furnaces and 
hydrogen production process unit heaters) are part of the hydrogen 
production source category and that their emissions are to be reported 
under subpart P. These amendments, which include a harmonizing change 
at 40 CFR 98.162(a), clarify that these furnaces or process heaters are 
part of the hydrogen production process unit regardless of where the 
emissions are exhausted (through the same stack or through separate 
stacks). Similarly, we are finalizing a clarification for hydrogen 
production units with separate stacks for ``process'' emissions and 
``combustion'' emission that use a CEMS to quantify emissions from the 
process emissions stack. The final amendments at 40 CFR 98.163(c) 
require reporters to calculate and report the CO2 emissions 
from the hydrogen production unit's fuel combustion using the mass 
balance equations (equations P-1 through P-3) in addition to 
calculating and reporting the process CO2 emissions measured 
by the CEMS. Additional information on these revisions and their 
supporting basis may be found in section III.G. of the preamble to the 
2023 Supplemental Proposal. We are adding one additional revision to 
address the monitoring of stationary combustion units directly 
associated with hydrogen production (e.g., reforming furnaces and 
hydrogen production process unit heaters), following a review of 
comments received. Based on the EPA's analysis of reported data, there 
may be a small number of reporters that may not currently measure the 
fuel use to these combustion units separately. We have decided to add 
new Sec.  98.164(c) to provide the use of best available monitoring 
methods (BAMM) for those facilities that may still need to install 
monitoring equipment to measure the fuel used by each stationary 
combustion unit directly associated with the hydrogen production 
process unit. To be eligible to use BAMM, the stationary combustion 
unit must be directly associated with hydrogen production; the unit 
must not have a measurement device installed as of January 1, 2025; the 
hydrogen production unit and the stationary combustion unit are 
operated continuously; and the installation of a measurement device 
must require a planned process equipment or unit shutdown or only be 
able to be done through a hot tap. BAMM can be the use of supplier 
data, engineering calculation methods, or other company records. We are 
not requiring facilities to provide an application to use BAMM that 
would require EPA review and approval to measure the fuel used in the 
hydrogen production process combustion unit. However, we are adding a 
new requirement at 40 CFR 98.166(d)(10) to require each facility to 
indicate in their annual report, for each stationary combustion unit 
directly associated with hydrogen production, whether they are using 
BAMM, the date they began using BAMM, and the anticipated or actual end 
date of BAMM use. Providing the use of BAMM is intended to reduce the 
burden associated with installation of new equipment, and we do not 
anticipate that the requirement to report the required indicators of 
BAMM will add significant burden. See section III.I.2. of this preamble 
for additional information on related comments and the EPA's response.
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
several amendments to subpart P to allow the subtraction of the mass of 
carbon contained in products (other than CO2 or methanol) 
and the carbon contained in intentionally produced methanol from the 
carbon mass balance used to estimate CO2 emissions. The 
proposed revisions included new equation P-4 to allow facilities to 
adjust the calculated emissions from fuel and feedstock consumption in 
order to calculate net CO2 process emissions, as well as 
harmonizing revisions to the introductory paragraph of 40 CFR 98.163 
and 98.163(b) and the reporting requirements at 40 CFR 98.167(b)(7). 
Following review of comments received on similar changes proposed for 
subpart S (Lime Manufacturing), the EPA is not taking final action at 
this time on the proposed revisions to allow facilities to subtract out 
carbon contained in products other than CO2 or methanol and 
the carbon contained in methanol. See sections III.E., III.I.2., and 
III.K.2. of this preamble for additional information on the comments 
related to subparts G, P and S and the EPA's response. However, the EPA 
is finalizing the proposed reporting requirement at 40 CFR 98.166(b)(7) 
(now 40 CFR 98.166(d)(7)), with minor revisions as a result of comments 
received. See the discussion in this section regarding subpart P 
reporting requirements for additional information as to why EPA is 
making revisions as a result of comments received.
    The EPA is finalizing several additional revisions to the subpart P 
reporting requirements to improve the quality of the data collected 
based on the 2022 Data Quality Improvements Proposal and the 2023 
Supplemental Proposal. The final reporting requirements are reorganized 
to accommodate the final amendments at 40 CFR 98.163(c), which require 
reporters using CEMS that do not include combustion emissions from the 
hydrogen production unit to calculate and report the CO2 
emissions from fuel combustion using the material balance equations 
(equations P-1 through P-3) in addition to the process CO2 
emissions measured by the CEMS. The revisions to 40 CFR 98.166 clarify 
the reporting elements that must be provided for each hydrogen 
production process unit based on the calculation methodologies used. 
Reporters using CEMS to measure combined CO2 process and 
fuel combustion emissions will be required

[[Page 31838]]

to meet the requirements at 40 CFR 98.166(b); reporters using only the 
material balance method will be required to meet the requirements at 40 
CFR 98.166(c); and reporters using CEMS to measure CO2 
process emissions and the material balance method to calculate 
emissions from fuel combustion emissions using equations P-1 through P-
3 will be required to meet the requirements of 40 CFR 98.166(b) and 
(c). If a common stack CEMS is used to measure emissions from either a 
common stack for multiple hydrogen production units or a common stack 
for hydrogen production unit(s) and other source(s), reporters must 
also report the estimated fraction of CO2 emissions 
attributable to each hydrogen production process unit. All other 
reporting requirements for each hydrogen production process unit 
(regardless of the calculation method) are consolidated under 40 CFR 
98.166(d).
    As proposed, we are finalizing the addition of requirements for 
facilities to report the process type for each hydrogen production unit 
(i.e., steam methane reforming (SMR), SMR followed by water gas shift 
reaction (SMR-WGS), partial oxidation (POX), partial oxidation followed 
by WGS (POX-WGS), Water Electrolysis, Brine Electrolysis, or Other 
(specify)), and the purification type for each hydrogen production unit 
(i.e., pressure swing adsorption (PSA), Amine Adsorption, Membrane 
Separation, Other (specify), or none); the final requirements have been 
moved to 40 CFR 98.166(d)(1) and (2) and paragraph (d)(1) has been 
revised to include ``autothermal reforming only'' and ``autothermal 
reforming followed by WGS'' as additional unit types.
    We are amending, as proposed, requirements to clarify that the 
annual quantity of hydrogen produced is the quantity of hydrogen that 
is produced ``. . . by reforming, gasification, oxidation, reaction, or 
other transformations of feedstocks,'' and to add reporting for the 
annual quantity of hydrogen that is only purified by each hydrogen 
production unit; the final requirements have been moved to 40 CFR 
98.166(d)(3) and (4).
    We are finalizing a requirement at 40 CFR 98.166(c) (proposed 40 
CFR 98.166(b)(5)), to report the name and annual quantity (metric tons 
(mt)) of each carbon-containing fuel and feedstock (formerly 40 CFR 
98.166(b)(7)). For clarity, we have revised the text of the requirement 
at 40 CFR 98.166(c) from proposal to specify that the information is 
required whenever equations P-1 through P-3 are used to calculate 
CO2 emissions. We are finalizing revisions that renumber 40 
CFR 98.166(c) and (d) (now 40 CFR 98.166(d)(6) and (7)), and are 
finalizing paragraph (d)(7) with revisions from those proposed to 
require reporting, on a unit-level: (1) the quantity of CO2 
that is collected and transferred off-site; and (2) the quantity of 
carbon other than CO2 or methanol collected and transferred 
off-site, or transferred to a separate process unit within the facility 
for which GHG emissions associated with the carbon is being reported 
under other provisions of part 98. The final rule also requires at 40 
CFR 98.166(d)(9) the reporting of the annual net quantity of steam 
consumed by the unit (proposed as 40 CFR 98.166(c)(9)). This value will 
be a positive quantity if the hydrogen production unit is a net steam 
user (i.e., uses more steam than it produces) and a negative quantity 
if the hydrogen production unit is a net steam producer (i.e., produces 
more steam than it uses).
    Finally, for consistency with the final revisions to the reporting 
requirements for facilities subject to revised 40 CFR 98.163(c), we are 
making a harmonizing change to the recordkeeping requirements at 40 CFR 
98.167(a) to specify that, if the facility CEMS measures emissions from 
a common stack for multiple hydrogen production units or emissions from 
a common stack for hydrogen production unit(s) and other source(s), 
reporters must maintain records used to estimate the decimal fraction 
of the total annual CO2 emissions from the CEMS monitoring 
location attributable to each hydrogen production unit. We are also 
finalizing as proposed clarifying edits in 40 CFR 98.167(e) that 
retention of the file required under that provision satisfies the 
recordkeeping requirements for each hydrogen production unit. See 
section III.G.1. of the preamble to the 2022 Data Quality Improvements 
Proposal and section III.G. of the preamble to the 2023 Supplemental 
Proposal for additional information on these revisions and their 
supporting basis.
    In the 2023 Supplemental Proposal, the EPA also requested comment 
on, but did not propose, other potential revisions to subpart P, 
including revisions that would remove the 25,000 mtCO2e 
threshold under 40 CFR 98.2(a)(2), which would result in a requirement 
that any facility meeting the definition of the hydrogen production 
category in 40 CFR 98.160 report annual emissions to the GHGRP. The EPA 
considered these changes in order to collect information on facilities 
that use electrolysis or other production methods that may have small 
direct emissions, but that may use relatively large amounts of off-site 
energy to power the process (i.e., the emissions occurring on-site at 
these hydrogen production facilities may fall below the existing 
applicability threshold, while the combined direct emissions (i.e., 
``scope 1'' emissions) and emissions attributable to energy consumption 
(i.e., ``scope 2'' emissions) could be relatively large), as collecting 
information from these kinds of facilities as well is especially 
important in understanding hydrogen as a fuel source. To reduce the 
burden on small producers, the EPA requested comment on applying a 
minimum annual production quantity within the source category 
definition to limit the applicability of the source category to larger 
hydrogen production facilities, such as defining the source category to 
only include those hydrogen production processes that exceed a 2,500 
metric ton (mt) hydrogen production threshold. The EPA also requested 
comment on potential options to require continued reporting from 
hydrogen production facilities that use electrolysis or other 
production methods that may have small direct emissions (i.e., scope 1 
emissions) that would likely qualify to cease reporting after three to 
five years under the part 98 ``off-ramp'' provisions of 40 CFR 98.2(i) 
(i.e., facilities may stop reporting after three years if their 
emissions are under 15,000 mtCO2e or after five years if 
their emissions are between 15,000 and 25,000 mtCO2e), to 
enable collection of a more comprehensive data set over time. Following 
consideration of comments received, the EPA is not taking final action 
on these potential revisions in this rule. See section III.I.2. of this 
preamble for additional information on related comments and the EPA's 
responses. The EPA also considered, but did not propose, further 
expanding the reporting requirements to include the quantity of 
hydrogen provided to each end-user (including both on-site use and 
delivered hydrogen) and, if the end-user reports to GHGRP, the e-GGRT 
identifier for that customer. The EPA requested comment on the approach 
to collecting this sales information and the burden such a requirement 
may impose in the 2023 Supplemental Proposal. Following review of 
comments received, the EPA is not taking final action on these 
potential revisions in this rule.
b. Revisions To Streamline and Improve Implementation for Subpart P
    The EPA is finalizing several revisions to subpart P to streamline 
the requirements of this subpart and improve flexibility for reporters. 
To

[[Page 31839]]

address the recent use of low carbon content feedstocks, the EPA is 
finalizing, with revisions from those proposed, revisions to 40 CFR 
98.164(b)(2) and (3) to allow the use of product specification 
information annually as specified in the final provisions for (1) 
gaseous fuels and feedstocks that have carbon content less than or 
equal to 20 parts per million by weight (i.e., 0.00002 kg carbon per kg 
of gaseous fuel or feedstock) (rather than at least weekly sampling and 
analysis), and (2) for liquid fuels and feedstocks that have a carbon 
content of less than or equal to 0.00006 kg carbon per gallon of liquid 
fuel or feedstock (rather than monthly sampling and analysis). As 
explained in the 2022 Data Quality Improvements Proposal, the fuels and 
feedstocks below these concentrations have very limited GHG emission 
potential and are currently an insignificant contribution to the GHG 
emissions from hydrogen production. The revisions from those proposed 
were included to remove the term ``non-hydrocarbon'' because it is not 
necessary since the maximum hydrocarbon concentrations that qualify for 
the revised monitoring requirements are included in 40 CFR 98.164(b)(2) 
and (3).
    The EPA is finalizing, with revisions from those proposed, the 
addition of new 40 CFR 98.164(b)(5)(xix) to allow the use of 
modifications of the methods listed in 40 CFR 98.164(b)(5)(i) through 
(xviii) or use of other methods that are applicable to the fuel or 
feedstock if the methods currently in 40 CFR 98.164(b)(5) are not 
appropriate because the relevant compounds cannot be detected, the 
quality control requirements are not technically feasible, or use of 
the method would be unsafe. The revisions from those proposed were 
harmonizing changes to remove the term ``non-hydrocarbon'' and tie the 
proposed revisions back more clearly to the specifications in 
paragraphs (b)(2) and (3).
    The final rule also finalizes as proposed, revisions to Sec.  
98.164(b)(2) through (4) to specifically state that the carbon content 
must be determined ``. . . using the applicable methods in paragraph 
(b)(5) of this section'' to clarify the linkage between the 
requirements in Sec.  98.164(b)(2) through (4) and Sec.  98.164(b)(5).
    Finally, the EPA is finalizing revisions to the recordkeeping 
requirements at 40 CFR 98.167(b) to refer to paragraph (b) of 40 CFR 
98.166. For facilities using the alternatives at 40 CFR 98.164(b)(2), 
(3) or (5)(xix), these requirements include retention of product 
specification sheets, records of modifications to the methods listed in 
40 CFR 98.164(b)(5)(i) through (xviii) that are used, and records of 
the alternative methods used, as applicable. We are also finalizing a 
revision to remove and reserve redundant recordkeeping requirements in 
40 CFR 98.167(c). See section III.G.2. of the preamble to the 2022 Data 
Quality Improvements Proposal and section III.G. of the preamble to the 
2023 Supplemental Proposal for additional information on these 
revisions and their supporting basis.
2. Summary of Comments and Responses on Subpart P
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart P. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart P.
    Comment: Two commenters recommended expanding the source category 
to include all hydrogen production facilities; this would include non-
merchant producers, facilities that use electrolysis or renewable 
energy, and include process units that do not report to other subparts. 
Other commenters did not oppose expanding the source category to non-
merchant facilities. One commenter on the 2022 Data Quality 
Improvements Proposal stated that the existing definition may cause 
confusion in situations where the hydrogen produced is used on-site or 
otherwise not ``sold as a product to other entities'' and suggested 
specific revisions to expand the source category to include other types 
of hydrogen production plants, including those using electrolysis. One 
commenter stated that reporting energy consumption by hydrogen 
production sources is necessary to inform decarbonization strategies, 
e.g., whether producing excessive amounts of green hydrogen may risk 
delaying fossil fuel retirement by diverting renewable energy from 
other uses. The commenter recommended a threshold for these facilities 
based on energy input. The commenter added that any hydrogen production 
facilities using carbon capture and sequestration technology should be 
required to report in all instances, as emissions data and energy 
consumption data from these facilities will be highly relevant to 
future regulatory action.
    Multiple commenters commented on the EPA's request for comment 
regarding removing the threshold for the hydrogen production source 
category. One commenter strongly urged the EPA to make subpart P an 
``all-in'' subpart to ensure all hydrogen production facilities are 
covered by reporting requirements, including the requirements proposed 
to report purchased energy consumption under proposed subpart B to part 
98. The commenter pointed to hydrogen electrolysis facilities that may 
consume very large amounts of grid electricity that could have 
significant upstream emissions impacts; the commenter stated that many 
or most of these facilities will already be tracking the attributes of 
the energy they consume to qualify for Federal incentives and 
investment, and will therefore have this information readily available. 
The commenter stressed that understanding this information and the 
lifecycle emissions of hydrogen production will be critical to 
informing future actions under the CAA. The commenter also supported a 
production-based reporting threshold to ensure reporting for high 
production facilities with lower direct emissions and suggested the 
production threshold should at least include at least the top 75 
percent of production facilities. One commenter suggested a hydrogen 
production threshold of 5,000 mt/year. Another commenter recommended 
that the EPA should implement a threshold to limit the applicability of 
the subpart to larger hydrogen production facilities. One commenter 
opposed a hydrogen production threshold, and recommended that the EPA 
retain the existing emissions-based threshold of 25,000 
mtCO2e; the commenter suggested this would further 
incentivize the implementation of low GHG hydrogen manufacturing 
processes over higher emitting processes such as steam methane 
reformers.
    Several commenters also opposed revisions that would remove the 
ability of sources to off-ramp. One commenter offered the following 
recommendations: (1) hydrogen production process units which produce 
hydrogen but emit no direct GHG emissions should become eligible to 
cease reporting starting January 1 of the following year after the 
cessation of direct GHG emitting activities associated with the 
process; (2) if the direct GHG emissions remain below 15,000 
mtCO2e or between 15,000 and 25,000 mtCO2e, 
reporting would be required for 3 or 5 years respectively, consistent 
with the existing off-ramp provisions; or (3) if the EPA establishes

[[Page 31840]]

a hydrogen production threshold for reporting, then falling below the 
production threshold should be the trigger for cessation of reporting, 
either starting January 1 of the following year or on a parallel 
structure to the three and five year off-ramp emission thresholds. Two 
other commenters stated that the EPA ignores that the ``off-ramp'' is 
intended for entities that should no longer be subject to reporting 
requirements by virtue of the fact that their emissions fall below a 
reasonable threshold. One commenter stated that it is unclear how the 
EPA would have authority to continue to require reporting for these 
entities, and the commenters said that the EPA should justify excluding 
hydrogen production facilities from the off-ramp. The commenters added 
that the EPA could use other methods to collect this data, including 
proposing a separate standard addressing emissions from hydrogen 
production under CAA section 111.
    Response: We agreed with commenters that the language regarding 
``hydrogen gas sold as a product to other entities'' could cause 
confusion, as we intended to require non-merchant hydrogen production 
units to now report under subpart P. As such, we are finalizing, as 
proposed in the 2023 Supplemental Proposal, the language in 40 CFR 
98.160(a) to focus on hydrogen gas production without referring to the 
disposition of the hydrogen produced. In the 2023 Supplemental 
Proposal, we also proposed to significantly revise Sec.  98.160(b) and 
(c). The supplemental proposal revisions appear to address most of the 
commenter's suggested revisions, except that we are not including 
``electrolysis'' in the list of types of transformations in 40 CFR 
98.160(b) because we consider electrolysis as already included under 
``. . . reaction, or other transformations of feedstocks.'' This is 
also supported by the inclusion of water electrolysis and brine 
electrolysis in the list of hydrogen production unit types in the 
proposed 40 CFR 98.166(b)(1)(i) (now 40 CFR 98.166(d)(1)). We agree 
with commenters that subpart P should be applicable to non-merchant 
facilities and are finalizing the proposed revisions.
    The EPA has considered comments both supporting and not supporting 
changes related to the EPA's request for information regarding removing 
the emissions-based threshold or introducing an alternative production-
based threshold for the hydrogen production source category, including 
options to require continued reporting from hydrogen production 
facilities by amending the emissions-based off-ramp provisions at 40 
CFR 98.2(i)(1) and (2). The EPA did not propose or provide for review 
specific revisions to part 98 to expand the source category, beyond the 
inclusion of non-merchant facilities as discussed in section III.I.1. 
of this preamble. Therefore, we are not including any revisions to the 
threshold to subpart P or to the ability of hydrogen production 
facilities to off-ramp in this final rule. However, the EPA may further 
consider these comments and the information provided as we evaluate 
next steps concerning the collection of information from hydrogen 
production facilities and consider approaches to improving our 
understanding of hydrogen as a fuel source, including to inform any 
potential future rulemakings.
    Comment: Three commenters did not support the requirement to report 
combustion from hydrogen production process units under subpart P in 
lieu of subpart C as proposed in 40 CFR 98.160(c). Two commenters 
stated that these units may not be metered separately from other 
combustion units located at an integrated facility, which would require 
additional metering to comply with subpart P reporting of combustion 
emissions directly associated with the hydrogen production process. 
These commenters stated that if combustion emissions directly 
associated with the hydrogen production process must be reported under 
subpart P, engineering estimations for fuel consumption should be 
allowed. One commenter recommended that EPA implement a threshold to 
limit the applicability of the subpart to larger hydrogen production 
facilities.
    Response: Steam methane reforming (SMR) is an endothermic process, 
and heating and reheating of fuels and feedstocks to maintain reaction 
temperatures is an integral part of the steam methane reforming 
reaction. Therefore, subpart P has always required the reporting of 
``fuels and feedstocks'' used in the hydrogen production unit and 
subpart C should only be used for ``. . . each stationary combustion 
unit other than hydrogen production process units'' (40 CFR 98.162(c)). 
We have long noted that the emissions from most SMR furnaces include a 
mixture of process and combustion emissions.\15\ For more accurate 
comparison of CEMS measured emissions with those estimated using the 
mass balance method, we required reporting of the combustion emissions 
from the SMR furnace as part of the subpart P emissions. Our proposed 
revisions, therefore, were not a new requirement, but a further 
clarification of the existing requirements in subpart P, as we 
interpret them. Based on previous reviews of the emissions intensities 
from hydrogen production as compiled from subpart P reported data, we 
estimate that there are only a few facilities that do not include the 
SMR furnace or process heaters combustion emissions in their subpart P 
emission totals. To allow time for those facilities to measure fuel 
used in stationary combustion units associated with hydrogen production 
(e.g., reforming furnaces and hydrogen production process unit 
heaters), we decided to include in this final rule a limited allowance 
for BAMM for those facilities that may still need to add appropriate 
monitoring equipment (as demonstrated through meeting the specified 
criteria in the final provision). We also note that subpart C units 
reporting under the common pipe reporting configuration at 40 CFR 
98.36(c)(3) may use company records to subtract out the portion of the 
fuel diverted to other combustion unit(s) prior to performing the GHG 
emissions calculations for the group of units using the common pipe 
option. Regarding the recommendation to implement a threshold to limit 
applicability to larger hydrogen production facilities, we are not 
taking final action on any revisions to the threshold to subpart P, 
therefore, facilities with hydrogen production plants will continue to 
determine applicability to part 98 based on the existing requirements 
of 40 CFR 98.2(a). A facility that contains a source category listed in 
table A-4 to subpart A of part 98 (which includes hydrogen production) 
must report only if the estimated combined annual emissions from 
stationary fuel combustion units, miscellaneous uses of carbonate, and 
all applicable source categories in tables A-3 and table A-4 of part 98 
are 25,000 mtCO2e or more. Therefore, the applicability of 
the subpart is already limited to larger hydrogen production 
facilities.
---------------------------------------------------------------------------

    \15\ See, e.g., https://ccdsupport.com/confluence/pages/viewpage.action?pageId=173080691.
---------------------------------------------------------------------------

    Comment: One commenter stated that EPA's proposed mass balance 
equation under 40 CFR 98.163(d), equation P-4, requires further 
revision to ensure that it is accurate for refineries that have non-
merchant hydrogen plants (such as those currently reporting under 
subpart Y). The commenter added that to ensure proper accounting, the 
variable ``Coftsite,n'' should be further revised to include 
language for non-merchant hydrogen plants as follows: ``Mass of carbon 
other than CO2 or methanol collected from the hydrogen 
production

[[Page 31841]]

unit and transferred off site or reported elsewhere by the facility 
under this part, from company records for month n (metric tons 
carbon).''
    Response: Following consideration of comments on similar proposed 
revisions in other subparts, as discussed in section III.K.2. of this 
preamble, we are not taking final action at this time on proposed 
amendments to equation P-4 to allow the subtraction of carbon contained 
in products other than CO2 or methanol and the carbon 
contained in methanol from the carbon mass balance used to estimate 
CO2 emissions. However, we acknowledge this concern and 
agree that an analogous scenario may also occur within a facility that 
contains a captive (non-merchant) hydrogen production process unit. For 
example, some hydrogen production processes may operate without the 
water-gas-shift reaction and produce a syngas of hydrogen and carbon 
monoxide. For merchant plants, this syngas would be sold as a product 
for use as a fuel or as a feedstock for chemical production process. 
For a non-merchant plant, the syngas may be used on-site as a fuel or 
feedstock rather than sold off-site as a product. If a captive hydrogen 
production unit produces syngas for use as a fuel for an on-site 
stationary combustion unit, for example, the rule as proposed would not 
have allowed the subtraction of the carbon in the syngas from the 
emissions from the hydrogen production unit, resulting in double 
counting the CO2 emissions related to this carbon (from both 
the hydrogen production unit and from the stationary combustion 
source). Most refineries with captive hydrogen production units seek to 
produce hydrogen for use in their refining process units and, 
therefore, use the water-gas-shift reaction to make pure hydrogen 
rather than syngas. However, production of syngas is possible under 
some circumstances. Although we are not finalizing equation P-4 as 
proposed, because the rule currently requires the reporting of carbon 
other than CO2 or methanol that is transferred off site, we 
have revised the reporting requirements to clarify that the reported 
value, for non-merchant hydrogen production facilities, should include 
the quantity of carbon other than CO2 or methanol that is 
transferred to a separate process unit within the facility for which 
GHG emissions associated with this carbon are being reported under 
other provisions of part 98.
    Comment: One commenter supported the separate reporting of hydrogen 
that is produced and hydrogen that is only purified, but requested that 
the EPA provide sufficient implementation time and allow for best 
available monitoring methods to be used until installation of necessary 
monitoring equipment could occur.
    Another commenter was supportive of reporting steam consumption 
data (i.e., annual net quantity of steam consumed). However, the 
commenter added that there may be situations where steam is sourced 
from equipment (e.g., a stand-alone boiler) distinct from a waste heat 
boiler associated with the SMR process; the commenter stated the rule 
should allow for flexibility in how the steam production and 
consumption is measured and quantified, including the ability to 
utilize best available monitoring methods.
    Other commenters opposed reporting steam consumption data. One 
commenter opposing the requirements stated it could result in 
duplicative reporting based on what is proposed to be reported under 
subpart B. Two commenters stated that the EPA failed to provide 
justification for the requirement. Two commenters stated that it may be 
necessary for the EPA to issue an additional supplemental notice of 
proposed rulemaking to take comment on any such justification.
    Response: Subpart P only provides monitoring requirements for fuels 
and feedstocks, it does not specify monitoring requirements for other 
reported data, for example, ammonia and methanol production. There are 
often cases in part 98 where there are reporting elements, but not 
specific monitoring requirements. In such cases, company records, 
engineering estimates, and similar approaches may be used (in addition 
to direct measurement methods) to report these quantities. As such, 
there is no need for BAMM provisions related to additional reporting 
requirements that require separately reporting produced and purified 
hydrogen quantities and net steam consumption.
    We also note that the subpart P requirement is process unit 
specific, which is not duplicative of the proposed subpart B facility- 
or subpart-level reporting requirements. We also disagree that we did 
not provide rationale for the proposed requirements. These requirements 
(as with many of the other proposed requirements for subpart P) are 
aimed to obtain better information to verify reported emissions. For 
example, if a facility is a net steam purchaser, some emissions 
resulting from activities that support the hydrogen production process 
may occur at the steam production site. Thus, knowing the net steam 
consumption may help explain why the emissions to production ratios for 
these facilities based on reported data do not fall within the expected 
ranges. Understanding this could result in less correspondence from the 
EPA to verify these facilities' reports and therefore reduce the burden 
to these facilities.

J. Subpart Q--Iron and Steel Production

    We are finalizing the amendments to subpart Q of part 98 (Iron and 
Steel Production) as proposed. This section discusses the final 
revisions to subpart Q. The EPA received comments on the proposed 
requirements for subpart Q; see the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart Q. Additional rationale 
for these amendments is available in the preamble to the 2022 Data 
Quality Improvements Proposal. We are also finalizing as proposed 
confidentiality determinations for new data elements resulting from the 
revisions to subpart Q as described in section VI. of this preamble.
1. Revisions To Improve the Quality of Data Collected for Subpart Q
    The EPA is finalizing revisions to subpart Q, as proposed in the 
2022 Data Quality Improvements Proposal, to enhance the quality and 
accuracy of the data collected. First, we are revising 40 CFR 98.176(g) 
for all unit types (taconite indurating furnace, basic oxygen furnace, 
non-recovery coke oven battery, sinter process, EAF, decarburization 
vessel, and direct reduction furnace) and all calculation methods 
(direct measurement using CEMS, carbon mass balance methodologies, or 
site-specific emission factors) to require that facilities report the 
type of unit, the annual production capacity, and the annual operating 
hours for each unit.
    The EPA is also finalizing revisions to correct equation Q-5 in 40 
CFR 98.173(b)(1)(v) to remove an error introduced into the equation in 
prior revisions (81 FR 89188, December 9, 2016). The final rule 
corrects the equation to remove an unnecessary fraction symbol. See 
section III.H.1. of the preamble to the 2022 Data Quality Improvements 
Proposal for additional information on these revisions and their 
supporting basis.
2. Revisions To Streamline and Improve Implementation for Subpart Q
    The EPA is finalizing two revisions to subpart Q to streamline 
monitoring. First, we are revising 40 CFR

[[Page 31842]]

98.174(b)(2) to provide the option for facilities to determine the 
carbon content of process inputs and outputs by use of analyses 
provided by material recyclers that manage process outputs for sale or 
use by other industries. Material recyclers conduct testing on their 
inputs and products to provide to entities using the materials 
downstream, and therefore perform carbon content analyses using similar 
test methods and procedures as suppliers. The final revisions include a 
minor harmonizing change to 40 CFR 98.176(e)(2) to require reporters to 
indicate if the carbon content was determined from information supplied 
by a material recycler.
    The EPA is also finalizing revisions to 40 CFR 98.174(b)(2) to 
incorporate a new test method, ASTM E415-17, Standard Test Method for 
Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission 
Spectrometry (2017), for carbon content analysis of low-alloy steel. 
The new method is incorporated by reference in 40 CFR 98.7 and 
98.174(b)(2) for use for steel, as applicable. The addition of this 
alternative test method will provide additional flexibility for 
reporters. We are also finalizing one harmonizing change to the 
reporting requirements of 40 CFR 98.176(e)(2), to clarify that the 
carbon content analysis methods available to report are those methods 
listed in 40 CFR 98.174(b)(2). See section III.H.2. of the preamble to 
the 2022 Data Quality Improvements Proposal for additional information 
on these revisions and their supporting basis.

K. Subpart S--Lime Production

    We are finalizing several amendments to subpart S of part 98 (Lime 
Production) as proposed. In some cases, we are finalizing the proposed 
amendments with revisions. Section III.K.1. of this preamble discusses 
the final revisions to subpart S. The EPA received several comments on 
the proposed subpart S revisions which are discussed in section 
III.K.2. of this preamble. We are also finalizing as proposed related 
confidentiality determinations for data elements resulting from the 
revisions to subpart S, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart S
    The EPA is finalizing several revisions to subpart S of part 98 
(Lime Manufacturing) as proposed to improve the quality of the data 
collected from this subpart. First, we are finalizing the addition of 
reporting requirements for reporters using the CEMS methodology, in 
order to improve our understanding of source category emissions and our 
ability to verify reported data. The EPA is adding data elements under 
40 CFR 98.196(a) to collect annual averages of the chemical composition 
input data on a facility-basis, including the annual arithmetic average 
calcium oxide content (mt CaO/mt tons lime) and magnesium oxide content 
(mt MgO/mt lime) for each type of lime produced, for each type of 
calcined lime byproduct and waste sold, and for each type of calcined 
lime byproduct and waste not sold. These data elements rely on an 
arithmetic average of the measurements rather than requiring reporters 
to weight by quantities produced in each month. Collecting average 
chemical composition data for CEMS facilities will provide the EPA the 
ability to develop a process emission estimation methodology for CEMS 
reporters, which can be used to verify the accuracy of the reported 
CEMS emission data.
    The EPA is also finalizing additional data elements for reporters 
using the mass balance methodology (i.e., reporters that comply using 
the requirements at 40 CFR 98.193(b)(2)). The final rule includes new 
data elements under 40 CFR 98.196(b) to collect the annual average 
results of the chemical composition analysis of all lime byproducts or 
wastes not sold (e.g., a single facility average calcium oxide content 
calculated from the calcium oxide content of all lime byproduct types 
at the facility), and the annual quantity of all lime byproducts or 
wastes not sold (e.g., a single facility total calculated as the sum of 
all quantities, in tons, of all lime byproducts at the facility not 
sold during the year). These amendments will allow the EPA to build 
verification checks for the actual inputs entered (e.g., MgO content). 
Because the final data elements rely on annual averages of the chemical 
composition measurements and an annual quantity of all lime byproducts 
or wastes at the facility, they are distinct from the data entered into 
the EPA's verification software tool. Additional information on these 
revisions and their supporting basis may be found in section III.I. of 
the preamble to the 2022 Data Quality Improvements Proposal.
    In the 2022 Data Quality Improvements Proposal, the EPA proposed to 
improve the methodology for calculation of annual CO2 
process emissions from lime production to account for CO2 
that is captured from lime kilns and used on-site. Specifically, we 
proposed to modify equation S-4 to subtract the CO2 that is 
captured and used in on-site processes, with corresponding revisions to 
the recordkeeping requirements in 40 CFR 98.197(c) (to record the 
monthly amount of CO2 from the lime manufacturing process 
that is captured for use in all on-site processes), minor amendments to 
the reporting elements in 40 CFR 98.196(b)(1) (to clarify reporting of 
annual net emissions), 40 CFR 98.196(b)(17) (to clarify reporters do 
not need to account for CO2 that was not captured but was 
used on-site), and to clarify that reporters must account for 
CO2 usage from all on-site processes, including for 
manufacture of other products, in the total annual amount of 
CO2 captured. Following consideration of comments received, 
the EPA is not taking final action at this time on the proposed 
revisions to equation S-4, or the corresponding revisions to 40 CFR 
98.196(b)(1) and 98.197(c). We are finalizing the clarifying revisions 
to 40 CFR 98.196(b)(17), as proposed. We are also finalizing an 
editorial correction to equation S-4 to add a missing equation symbol. 
See section III.K.2. of this preamble for additional information on 
related comments and the EPA's response.
2. Summary of Comments and Responses on Subpart S
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart S. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart S.
    Comment: One commenter opposed the proposed modifications to 
equation S-4 requiring monthly subtraction of CO2 used on-
site, stating it would be considerably more burdensome for lime 
producers that currently track and report this usage on an annual 
basis. The commenter requested that the EPA continue to allow the 
annual reporting of CO2 usage, and thus implement an annual 
subtraction from total process emissions from all lime kilns combined.
    Response: The EPA proposed revisions to subparts G (Ammonia 
Manufacturing), P (Hydrogen Production), and S (Lime Manufacturing) 
that would have required monthly measurement of captured CO2 
used to manufacture other products on-site or non-CO2 carbon 
sent off-site to external users. It would also have modified the 
subpart-level equations to require that these amounts

[[Page 31843]]

be subtracted from the emissions total. However, the EPA needs 
additional time to consider these comments and whether a consistent 
approach across these three subparts should be required or whether 
there are circumstances where alternative approaches might be 
warranted. Therefore, the EPA is not taking final action on these 
proposed revisions to subparts G, P, and S for at this time but may 
consider implementing these or similar revisions in future rulemakings.

L. Subpart U--Miscellaneous Uses of Carbonate

    The EPA is finalizing one minor change to subpart U of part 98 
(Miscellaneous Uses of Carbonate). The revision in this final rule is a 
harmonizing change following review of comments received on proposed 
subpart ZZ to part 98 (Ceramics Manufacturing) (see section III.EE. of 
this preamble for additional information on the related comments and 
the EPA's response). We are revising the source category definition for 
subpart U at 40 CFR 98.210(b) to clarify that ceramics manufacturing is 
excluded from the source category. Section 98.210(b) excludes equipment 
that uses carbonates or carbonate-containing materials that are 
consumed in production of cement, glass, ferroalloys, iron and steel, 
lead, lime, phosphoric acid, pulp and paper, soda ash, sodium 
bicarbonate, sodium hydroxide, or zinc. We are adding the text ``or 
ceramics'' to ensure that there is no duplicative reporting between 
subpart U and new subpart ZZ.

M. Subpart X--Petrochemical Production

    We are finalizing several amendments to subpart X of part 98 
(Petrochemical Production) as proposed. This section summarizes the 
final revisions to subpart X. The EPA received only minor comments on 
the proposed requirements for subpart X. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart X.
    We are finalizing as proposed several amendments to subpart X to 
improve the quality of data reported and to clarify the calculation, 
recordkeeping, and reporting requirements. First, we are finalizing a 
clarification to the emissions calculation requirements for flares in 
40 CFR 98.243(b)(3) and (d)(5) to cross-reference 40 CFR 98.253(b) of 
subpart Y; these revisions clarify that subpart X reporters are not 
required to report emissions from combustion of pilot gas and from gas 
released during startup, shutdown, and malfunction (SSM) events of 
<500,000 standard cubic feet (scf)/day that are excluded from equation 
Y-3.
    Next, we are finalizing as proposed the addition of new reporting 
requirements intended to improve the quality of the data collected 
under the GHGRP. First, we are finalizing reporting a new data element 
in 40 CFR 98.246(b)(7) and (c)(3). For each flare that is reported 
under the CEMS and optional ethylene combustion methodologies, 
facilities must report the estimated fractions of the total 
CO2, CH4, and N2O emissions from each 
flare that are due to combusting petrochemical off-gas. The final rule 
will allow the fractions attributed to each petrochemical process unit 
that routes emissions to the flare to be estimated using engineering 
judgment. This change will allow more accurate quantification of 
emissions both from individual petrochemical process units and from the 
industry sector as a whole. Next, the EPA is finalizing addition of a 
requirement in 40 CFR 98.246(c)(6) to report the names and annual 
quantity (in metric tons) of each product produced in each ethylene 
production process for emissions estimated using the optional ethylene 
combustion methodology; this improves consistency with the product 
reporting requirements under the CEMS and mass balance reporting 
options.
    We are finalizing, as proposed, a number of amendments that are 
intended to remove redundant or overlapping requirements and to clarify 
the data to be reported, as follows:
     For facilities that use the mass balance approach, we are 
finalizing amendments to 40 CFR 98.246(a)(2) to remove the requirement 
to report feedstock and product names, which previously overlapped with 
reporting requirements in 40 CFR 98.246(a)(12) and (13).
     We are finalizing revisions to 40 CFR 98.246(a)(5) to 
clarify the petrochemical and product reporting requirements for 
integrated ethylene dichloride/vinyl chloride monomer (EDC/VCM) process 
units. The amendments clarify the rule for facilities with an 
integrated EDC/VCM process unit that withdraw small amounts of the EDC 
as a separate product stream. The final rule is revised at 40 CFR 
98.246(a)(5) to specify that (1) the portion of the total amount of EDC 
produced that is an intermediate in the production of VCM may be either 
a measured quantity or an estimate; (2) the amount of EDC withdrawn 
from the process unit as a separate product (i.e., the portion of EDC 
produced that is not utilized in the VCM production) is to be measured 
in accordance with 40 CFR 98.243(b)(2) or (3); and (3) the sum of the 
two values is to be reported under 40 CFR 98.246(a)(5) as the total 
quantity of EDC petrochemical from an integrated EDC/VCM process unit.
     We are finalizing a change in 40 CFR 98.246(a)(13) to 
clarify that the amount of EDC product to report from an integrated 
EDC/VCM process unit should be only the amount of EDC, if any, that is 
withdrawn from the integrated process unit and not used in the VCM 
production portion of the integrated process unit.
     For facilities that use CEMS, we are finalizing amendments 
to 40 CFR 98.246(b)(8) to clarify the reporting requirements for the 
amount of EDC petrochemical when using an integrated EDC/VCM process 
unit, by removing language related to considering the petrochemical 
process unit to be the entire integrated EDC/VCM process unit.
     For facilities that use the optional ethylene combustion 
methodology to determine emissions from ethylene production process 
units, we are finalizing revisions to 40 CFR 98.246(c)(4) to clarify 
that the names and annual quantities of feedstocks that must be 
reported will be limited to feedstocks that contain carbon.
     We are finalizing changes to 40 CFR 98.246(a)(15) to more 
clearly specify that molecular weight must be reported for gaseous 
feedstocks and products only when the quantity of the gaseous feedstock 
or product used in equation X-1 is in standard cubic feet; the 
molecular weight does not need to be reported when the quantity of the 
gaseous feedstock or product is in kilograms.
    Additional information on the EPA's rationale for these revisions 
may be found in section III.K. of the preamble to the 2022 Data Quality 
Improvements Proposal.
    We are also finalizing as proposed confidentiality determinations 
for new data elements resulting from the revisions to subpart X, as 
described in section VI. of this preamble.

N. Subpart Y--Petroleum Refineries

    We are finalizing several amendments to subpart Y of part 98 
(Petroleum Refineries) as proposed. This section summarizes the final 
revisions to subpart Y. The EPA received several comment letters on the 
proposed

[[Page 31844]]

requirements for subpart Y. See the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart Y.
    We are also finalizing as proposed confidentiality determinations 
for new data elements resulting from the revisions to subpart Y, as 
described in section VI. of this preamble.
1. Revisions To Improve the Quality of Data Collected for Subpart Y
    The EPA is finalizing as proposed several amendments to subpart Y 
of part 98 to improve data collection, clarify rule requirements, and 
correct an error in the rule. First, we are finalizing amendments to 
the provisions for delayed coking units (DCU) to add reporting 
requirements for facilities using mass measurements from company 
records to estimate the amount of dry coke at the end of the coking 
cycle in 40 CFR 98.256(k)(6)(i) and (ii). These new paragraphs will 
require facilities to additionally report, for each DCU: (1) the 
internal height of the DCU vessel; and (2) the typical distance from 
the top of the DCU vessel to the top of the coke bed (i.e., coke drum 
outage) at the end of the coking cycle (feet). These new elements will 
allow the EPA to estimate and verify the reported mass of dry coke at 
the end of the cooling cycle as well as the reported DCU emissions.
    We are also finalizing revisions to equation Y-18b in 40 CFR 
98.253(i)(2), to include a new variable ``fcoke'' to allow 
facilities that do not completely cover the coke bed with water prior 
to venting or draining to accurately estimate the mass of water in the 
drum. The ``fcoke'' variable is defined as the fraction of 
coke-filled bed that is covered by water at the end of the cooling 
cycle just prior to atmospheric venting or draining, where a value of 
one (1) represents cases where the coke is completely submerged in 
water. The second term in equation Y-18b represents the volume of coke 
in the drum, and is subtracted from the water-filled coke bed volume to 
determine the volume of water. We are also finalizing revisions to the 
equation terms ``Mwater'' and ``Hwater'' to add 
the phase ``or draining'' to specify that these parameters reflect the 
mass of water and the height of water, respectively, at the end of the 
cooling cycle just prior to atmospheric venting or draining. We are 
finalizing harmonizing revisions to the recordkeeping requirements at 
40 CFR 98.257(b)(45) and (46) and a corresponding recordkeeping 
requirement at 40 CFR 98.257(b)(53).
    To help clarify that the calculation methodologies in 40 CFR 
98.253(c) and 98.253(e) are specific to coke burn-off emissions, we are 
finalizing the addition of ``from coke burn-off'' immediately after the 
first occurrence of ``emissions'' in the introductory text of 40 CFR 
98.253(c) and 98.253(e).
    We are also finalizing corrections to an inconsistency 
inadvertently introduced into subpart Y by amendments published on 
December 9, 2016 (81 FR 89188), which created an apparent inconsistency 
about whether to include or exclude SSM events less than 500,000 scf/
day in equation Y-3. This final rule clarifies in 40 CFR 98.253(b) that 
SSM events less than 500,000 scf/day may be excluded, but only if 
reporters are using the calculation method in 40 CFR 98.253(b)(1)(iii). 
We are also finalizing revisions to remove the recordkeeping 
requirements in existing 40 CFR 98.257(b)(53) through (56) and to 
reserve 40 CFR 98.257(b)(54) through (56). These requirements should 
have been removed in the December 9, 2016 amendments, which removed the 
corresponding requirement in 40 CFR 98.253(j) to calculate 
CH4 emissions from DCUs using the process vent method 
(equation Y-19). The EPA is also finalizing corrections to an erroneous 
cross-reference in 40 CFR 98.253(i)(5), which inaccurately defines the 
term ``Mstream'' in equation Y-18f for DCUs, to correct the 
cross-reference to Sec.  98.253(i)(4) instead of Sec.  98.253(i)(3). 
Additional information on the EPA's rationale for these revisions may 
be found in section III.L.1. of the preamble to the 2022 Data Quality 
Improvements Proposal.
    The EPA is finalizing as proposed one additional revision to 
improve data quality from the 2023 Supplemental Proposal. Specifically, 
we are finalizing the addition of a requirement to report the capacity 
of each asphalt blowing unit, consistent with the existing reporting 
requirements for other emissions units under subpart Y. The final rule 
requires that facilities provide the maximum rated unit-level capacity 
of the asphalt blowing unit, measured in mt of asphalt per day, in 40 
CFR 98.256(j)(2). Additional information on the EPA's rationale for 
these revisions may be found in section III.H. of the preamble to the 
2023 Supplemental Proposal.
2. Revisions To Streamline and Improve Implementation for Subpart Y
    The EPA is finalizing one change to subpart Y to streamline 
monitoring. We are finalizing an option for reporters to use mass 
spectrometer analyzers to determine gas composition and molecular 
weight without the use of a gas chromatograph. The final rule adds the 
inclusion of direct mass spectrometer analysis as an allowable gas 
composition method in 40 CFR 98.254(d). This change will allow 
reporters to use the same analyzers used for process control or for 
compliance with continuous sampling which are proposed to be provided 
under the National Emissions Standards for Hazardous Air Pollutants 
from Petroleum Refineries (40 CFR part 63, subpart CC), to comply with 
GHGRP requirements in subpart Y. Additional information on these 
revisions and their supporting basis may be found in section III.L.2. 
of the preamble to the 2022 Data Quality Improvements Proposal.
    Consistent with changes we are finalizing to subpart P of part 98 
(Hydrogen Production) from the 2023 Supplemental Proposal, we are 
finalizing revisions to remove references to non-merchant hydrogen 
production plants in 40 CFR 98.250(c) and to delete and reserve 40 CFR 
98.252(i), 98.255(d), and 98.256(b). We are also finalizing as proposed 
revisions to remove references to coke calcining units in 40 CFR 
98.250(c) and 98.257(b)(16) through (19) and to remove and reserve 40 
CFR 98.252(e), 98.253(g), 98.254(h), 98.254(i), 98.256(i), and 
98.257(b)(27) through (31). As proposed in the 2023 Supplemental 
Proposal, we are finalizing the addition of new subpart WW to part 98 
(Coke Calciners), and these provisions are no longer necessary under 
subpart Y. Additional information on these revisions and their 
supporting basis may be found in section III.H. of the preamble to the 
2023 Supplemental Proposal.

O. Subpart AA--Pulp and Paper Manufacturing

    We are finalizing the amendments to subpart AA of part 98 (Pulp and 
Paper Manufacturing) as proposed. The EPA received no comments 
regarding the proposed revisions to subpart AA. Additional rationale 
for these amendments is available in the preamble to the 2023 
Supplemental Proposal. The EPA is revising 40 CFR 98.273 to add a 
biogenic calculation methodology for estimation of CH4, 
N2O, and biogenic CO2 emissions for units that 
combust biomass fuels (other

[[Page 31845]]

than spent liquor solids) from table C-1 to subpart C of part 98 or 
that combust biomass fuels (other than spent liquor solids) with other 
fuels. We are also revising 40 CFR 98.276(a) to remove incorrect 
references to biogenic CH4 and N2O and correcting 
a typographical error at 40 CFR 98.277(d), as proposed. Additional 
rationale for these amendments is available in the preamble to the 2023 
Supplemental Proposal.

P. Subpart BB--Silicon Carbide Production

    We are finalizing the amendments to subpart BB of part 98 (Silicon 
Carbide Production) as proposed. The EPA received no comments regarding 
the proposed revisions to subpart BB. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal. The EPA is finalizing a reporting requirement at 
40 CFR 98.286(c) such that if CH4 abatement technology is 
used at silicon carbide production facilities, then facilities must 
report: (1) the type of CH4 abatement technology used and 
the date of installation for each technology; (2) the CH4 
destruction efficiency (percent destruction) for each CH4 
abatement technology; and (3) the percentage of annual operating hours 
that CH4 abatement technology was in use for all silicon 
carbide process units or production furnaces combined. For each 
CH4 abatement technology, reporters must either use the 
manufacturer's specified destruction efficiency or the destruction 
efficiency determined via a performance test; if the destruction 
efficiency is determined via a performance test, reporters must also 
report the name of the test method that was used during the performance 
test. Following the initial annual report containing this information, 
reporters will not be required to resubmit this information unless the 
information changes during a subsequent reporting year, in which case, 
the reporter must update the information in the submitted annual 
report. The final revisions to subpart BB also add a recordkeeping 
requirement at 40 CFR 98.287(d) for facilities to maintain a copy of 
the reported information. Additional rationale for these amendments is 
available in the preamble to the 2022 Data Quality Improvements 
Proposal. The EPA is also finalizing, as proposed, confidentiality 
determinations for the additional data elements to be reported as 
described in section VI. of this preamble.

Q. Subpart DD--Electrical Transmission and Distribution Equipment Use

    We are finalizing several amendments to subpart DD of part 98 
(Electrical Transmission and Distribution Equipment Use) as proposed. 
In some cases, we are finalizing the proposed amendments with 
revisions. Section III.Q.1. of this preamble discusses the final 
revisions to subpart DD. The EPA received several comments on the 
proposed subpart DD revisions which are discussed in section III.Q.2. 
of this preamble. We are also finalizing as proposed confidentiality 
determinations for new data elements resulting from the final revisions 
to subpart DD, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart DD
    This section summarizes the final amendments to subpart DD. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other final 
revisions to 40 CFR part 98, subpart DD can be found in this section 
and section III.Q.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart DD
    The EPA is finalizing several revisions to subpart DD to improve 
the quality of the data collected under this subpart. First, we are 
generally finalizing the proposed revisions to the calculation, 
monitoring, and reporting requirements of subpart DD to require 
reporting of additional F-GHGs, except insulating gases with weighted 
average GWPs less than or equal to one will remain excluded from 
reporting under subpart DD. These final amendments will help to account 
for use and emissions of replacements for SF6, including 
fluorinated gas mixtures, with lower but still significant GWPs. We are 
revising 40 CFR 98.300(a) to redefine the source category to include 
equipment containing ``fluorinated GHGs (F-GHGs), including but not 
limited to sulfur-hexafluoride (SF6) and perfluorocarbons 
(PFCs).'' These changes include:
     Revising the threshold determination in 40 CFR 98.301 by 
adding new equations DD-1 and equation DD-2 (see section III.Q.1.b. of 
this preamble).
     Revising the GHGs to report at 40 CFR 98.302 by adding a 
new equation DD-3, which is also used in the definition of ``reportable 
insulating gas,'' discussed below.
     Redesignating equation DD-1 as equation DD-4 at 40 CFR 
98.303 and revising the equation to estimate emissions from all F-GHGs 
within the existing calculation methodology, including F-GHG mixtures. 
Equation DD-4 will maintain the facility-level mass balance approach of 
tracking and accounting for decreases, acquisitions, disbursements, and 
net increase in total nameplate capacity for the facility each year, 
but will apply the weight fraction of each F-GHG to determine the user 
emissions by gas. In the final rule, we are making two clarifications 
to equation DD-4 in addition to the revisions that were proposed. These 
are discussed further below.
     Updating the monitoring and quality assurance requirements 
at 40 CFR 98.304(b) to account for emissions from additional F-GHGs.
     To address references to F-GHGs and F-GHG mixtures, we are 
finalizing the term ``insulating gas'' which is defined as ``any 
fluorinated GHG or fluorinated GHG mixture, including but not limited 
to SF6 and PFCs, that is used as an insulating and/or arc 
quenching gas in electrical equipment.''
     To clarify which insulating gases are subject to reporting 
requirements, we are adding the term ``reportable insulating gas,'' 
which is defined as ``an insulating gas whose GWP, as calculated in 
equation DD-3, is greater than one. A fluorinated GHG that makes up 
either part or all of a reportable insulating gas is considered to be a 
component of the reportable insulating gas.'' In many though not all 
cases, we are replacing occurrences of the proposed phrase 
``fluorinated GHGs, including PFCs and SF6'' with 
``fluorinated GHGs that are components of reportable insulating 
gases.''
     Adding harmonizing requirements to the term ``facility'' 
in the definitions section at 40 CFR 98.308 and the requirements at 40 
CFR 98.302, 98.305, and 98.306 to require reporters to account for the 
mass of each F-GHG for each electric power system.
    As noted above, following consideration of comments received, the 
EPA is revising these requirements from proposal to continue to exclude 
insulating gases with weighted average 100-year GWPs of less than one. 
Based on a review of the subpart DD data submitted to date, the EPA has 
concluded that excluding insulating gases with GWPs of less than one 
from reporting under subpart DD will have little effect on the accuracy 
or completeness of the GWP-weighted totals reported under subpart DD or

[[Page 31846]]

under the GHGRP generally at this time, and will decrease the reporting 
burden for facilities. See section III.Q.2. of this preamble for a 
summary of the related comments and the EPA's response.
    Also as noted above, we are making two clarifications to equation 
DD-4 in addition to the revisions that were proposed. First, to account 
for the possibility that the same fluorinated GHG could be a component 
of multiple reportable insulating gases, we are inserting a summation 
sign at the beginning of the right side of equation DD-4 to ensure that 
emissions of each fluorinated GHG ``i'' are summed across all 
reportable insulating gases ``j.'' Second, upon further consideration 
of equation DD-4 and its relationship to the newly defined terms ``new 
equipment'' and ``retiring equipment,'' we are modifying the terms for 
acquisitions and disbursements of reportable insulating gas j to 
account for acquisitions and disbursements of reportable insulating gas 
that are linked to the acquisition or sale of all or part of an 
electric power system. These include acquisitions or disbursements of 
reportable insulating gas inside equipment that is transferred while in 
use, acquisitions or disbursements of insulating gas inside equipment 
that is transferred from or to entities other than electrical equipment 
manufacturers and distributors while the equipment is not in use, and 
acquisitions or disbursements of insulating gas in bulk from or to 
entities other than chemical producers or distributors. Accounting for 
these acquisitions and disbursements in equation DD-4 ensures that the 
terms for acquisitions and disbursements of reportable insulating gas 
will be mathematically consistent with other terms in the equation, 
including the terms for the net increase in total nameplate capacity 
and the quantity of gas stored in containers at the end of the year. 
The term for the net increase in the total nameplate capacity will 
reflect the new definitions of ``new equipment'' and ``retiring 
equipment,'' which include transfers of equipment while in use. 
Similarly, the term for the quantity of reportable insulating gas 
stored in containers at the end of the year will reflect acquisitions 
or disbursements of reportable insulating gas stored in containers from 
or to all other entities, including other electric power systems. If 
these acquisitions or disbursements of gas in equipment or in bulk are 
not accounted for in the equation, the result will be incorrect. The 
revised terms are consistent with the definitions of ``new'' and 
``retired'' in their treatment of hermetically sealed pressure 
equipment, with such equipment being included in terms related to 
equipment that is transferred while not in use, but excluded from terms 
related to equipment that is transferred while in use. We are also 
making harmonizing changes to the reporting requirements at 40 CFR 
98.306, revising paragraphs (f), (g), and (i) (to be redesignated as 
paragraph (k)), and adding paragraphs (i), (n), and (o). These 
harmonizing revisions do not substantively change the reporting 
requirements as proposed and therefore would not substantively impact 
the burden to reporters.
    With minor changes, we are finalizing the proposed requirements in 
40 CFR 98.303(b) for users of electrical equipment to follow certain 
procedures when they elect to measure the nameplate capacities (in 
units of mass of insulating gas) of new and retiring equipment rather 
than relying on the rated nameplate capacities provided by equipment 
manufacturers. As proposed, this option will be available only for 
closed pressure equipment with a voltage capacity greater than 38 
kilovolts (kV), not for hermetically sealed pressure equipment or 
smaller closed-pressure equipment. These procedures are intended to 
ensure that the nameplate capacity values that equipment users measure 
match the full and proper charges of insulating gas in the electrical 
equipment. These procedures are similar to and compatible with the 
procedures for measuring nameplate capacity adopted by the California 
Air Resources Board (CARB) in its Regulation for Reducing Greenhouse 
Gas Emissions from Gas Insulated Switchgear.\16\
---------------------------------------------------------------------------

    \16\ See https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2020/sf6/fro.pdf.
---------------------------------------------------------------------------

    Specifically, electrical equipment users electing to measure the 
nameplate capacities of any new or retiring equipment will be required 
at 40 CFR 98.303(b)(1) to measure the nameplate capacities of all 
eligible new and retiring equipment in that year and in all subsequent 
years. For each piece of equipment, the electrical equipment user will 
be required to calculate the difference between the user-measured and 
rated nameplate capacities, verifying that the rated nameplate capacity 
was the most recent available from the equipment manufacturer. Where a 
user-measured nameplate capacity differs from the rated nameplate 
capacity by two percent or more, the electrical equipment user will be 
required at 40 CFR 98.303(b)(2) to adopt the user-measured nameplate 
capacity for that equipment for the remainder of the equipment's life. 
Where a user-measured nameplate capacity differs from the rated 
nameplate capacity by less than two percent, the electrical equipment 
user will have the option at 40 CFR 98.303(b)(3) to adopt the user-
measured nameplate capacity, but if they chose to do so, they must 
adopt the user-measured nameplate capacities for all new and retiring 
equipment whose user-measured nameplate capacity differed from the 
rated nameplate capacity by less than two percent.
    With minor changes, the EPA is finalizing the proposed requirements 
at 40 CFR 98.303(b)(4) and (5) for when electrical equipment users 
measure the nameplate capacity of new equipment that they install and 
for when they measure the nameplate capacity of retiring equipment. 
These final requirements ensure that electrical equipment users:
     Correctly account for the mass of insulating gas contained 
in new equipment upon delivery from the manufacturer (i.e., the holding 
charge), and correctly account for the mass of insulating gas contained 
in equipment upon retirement, measuring the actual temperature-adjusted 
pressure and comparing that to the temperature-adjusted pressure that 
reflects the correct filling density of that equipment.
     Use flowmeters or weigh scales that meet certain accuracy 
and precision requirements to measure the mass of insulating gas added 
to or recovered from the equipment;
     Use pressure-temperature charts and pressure gauges and 
thermometers that meet certain accuracy and precision requirements to 
fill equipment to the density specified by the equipment manufacturer 
or to recover the insulating gas from the equipment to the correct 
blank-off pressure, allowing appropriate time for temperature 
equilibration; and
     Ensure that insulating gas remaining in the equipment, 
hoses and gas carts is correctly accounted for.
    After consideration of comments, we are including a requirement to 
follow the procedure specified by the equipment manufacturer to ensure 
that the measured temperature accurately reflects the temperature of 
the insulating gas, e.g., by measuring the insulating gas pressure and 
vessel temperature after allowing appropriate time for the temperature 
of the transferred gas to equilibrate with the vessel temperature. Also 
after consideration of comments, we are (1) adding a requirement that 
facilities that use flow meters to measure the mass of insulating gas 
added to new equipment must keep the

[[Page 31847]]

mass flow rate within the range specified by the flowmeter 
manufacturer, and (2) not finalizing the option to use mass flowmeters 
to measure the mass of the insulating gas recovered from equipment. We 
are making both changes because the accuracy and precision of 
flowmeters can decrease significantly when the mass flow rate declines 
below the minimum specified by the flow meter manufacturer for accurate 
and precise measurements.
    As proposed, we are allowing equipment users to account for any 
leakage from the equipment using one of two approaches. In both 
approaches, users must measure the temperature-compensated pressure of 
the equipment before they remove the insulating gas from that equipment 
and compare the measured temperature-compensated pressure to the 
temperature-compensated pressure corresponding to the full and proper 
charge of the equipment (the design operating pressure). If the 
measured temperature-compensated pressure is different from the 
temperature-compensated pressure corresponding to the full and proper 
charge of the equipment, the equipment user may either (1) add or 
remove insulating gas to or from the equipment until the equipment 
reaches its full and proper charge; recover the gas until the equipment 
reached a pressure of 0.068 pounds per square inch, absolute (psia) 
(3.5 Torr) or less; and weigh the recovered gas (charge adjustment 
approach), or (2) if (a) the starting pressure of the equipment is 
between its temperature-compensated design operating pressure and five 
(5) pounds per square inch (psi) below that pressure, and (b) the 
insulating gas is recovered to a pressure no higher than 5 psia (259 
Torr),\17\ recover the gas that was already in the equipment; weigh it; 
and account mathematically for the difference between the quantity of 
gas recovered from the equipment and the full and proper charge 
(mathematical adjustment approach, equation DD-5).
---------------------------------------------------------------------------

    \17\ While the mathematical adjustment approach is expected to 
yield accurate results if the final pressure is 5 psia or less, 
facilities are encouraged to recover the insulating gas until they 
reach the blank-off pressure of the gas cart, which is generally 
expected to fall below 5 psia. Note that where the final pressure is 
equal to or less than 0.068 psia, the gas remaining in the equipment 
is estimated to account for a negligible share of the total and 
therefore facilities are not required to use the Mathematical 
Adjustment Method to account for it.
---------------------------------------------------------------------------

    In the final rule, we are allowing use of the mathematical 
adjustment approach in somewhat more limited circumstances than 
proposed. We proposed that to use the mathematical adjustment approach 
to calculate the nameplate capacity, facilities would need to recover a 
quantity of insulating gas equivalent to at least 90 percent of the 
full manufacturer-rated nameplate capacity of the equipment, which 
would have provided more flexibility on the starting and ending 
pressures of the equipment during the recovery process. The proposed 
requirement was based on an analysis of the proposed accuracies and 
precisions of measuring devices and their impacts on the accuracy and 
precision of the mathematical adjustment approach, which indicated that 
90 percent of the gas must be recovered to limit the uncertainty of the 
calculation to below 2 percent. We also recognized that departures from 
the ideal gas law could result in additional, systematic errors in the 
mathematical adjustment approach and therefore requested comment on the 
option of adding compressibility factors, which account for these 
departures, to equation DD-5 (proposed as equation DD-4). Such 
compressibility factors are not constant but are functions of the 
pressure and temperature of the insulating gas based on an equation of 
state specific to that insulating gas. We did not receive any comment 
on this option, and after considering the matter further, we believe 
that performing calculations using compressibility factors would prove 
too complex to implement in the field to obtain accurate nameplate 
capacity values. Without compressibility factors, departures of the 
insulating gas from the ideal gas law limit the reliability of the 
mathematical adjustment approach except within the ranges of starting 
and ending pressures described above. Consequently, we are finalizing 
the mathematical adjustment method as proposed but are restricting its 
use to the specified ranges of starting and ending pressures. Under 
these circumstances, any systematic errors in the mathematical 
adjustment approach are generally expected to fall below 0.5 percent, 
leading to maximum total errors (accounting for both departures from 
the ideal gas law and limits on the accuracy and precision of measuring 
devices) of approximately two percent. (For more discussion of this 
issue, see ``Update to the Technical Support for Proposed Revisions to 
Subpart DD, Electrical Transmission and Distribution Equipment Use,'' 
included in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424).
    Given these restrictions, the mathematical adjustment approach 
cannot be used to calculate the nameplate capacity of equipment that 
cannot have the insulating gas inside of it recovered below atmospheric 
pressure. However, as noted above, the approach can still be used for 
situations where the blank-off pressure of a gas cart is above 3.5 Torr 
(0.068 psia) but below 5 psia and/or where the starting pressure of the 
electrical equipment is no more than 5 psi lower than its temperature-
compensated design operating pressure. (Note that equipment whose 
starting pressure is above the temperature-compensated design operating 
pressure will need to have the excess gas recovered until it reaches 
the design operating pressure, at which point the nameplate capacity 
measurement can begin.)
    We are finalizing as proposed requirements at 40 CFR 98.303(b)(6) 
that allow users to measure the nameplate capacity of electrical 
equipment earlier during maintenance activities that require opening 
the gas compartment. The equipment user will still be required to 
follow the measurement procedures required for retiring equipment at 40 
CFR 98.303(b)(5) to measure the nameplate capacity, and the measured 
nameplate capacity must be recorded, but will not be used in equation 
DD-3 until that equipment is actually retired.
    We are finalizing as proposed requirements at 40 CFR 98.303(b)(7) 
and (8) to require that, where the electrical equipment user is 
adopting the user-measured nameplate capacity, the user must affix a 
revised nameplate capacity label showing the revised nameplate value 
and the year the nameplate capacity adjustment process was performed to 
the device by the end of the calendar year in which the process was 
completed. For each piece of electrical equipment whose nameplate 
capacity is adjusted during the reporting year, the revised nameplate 
capacity value must be used in all rule provisions wherein the 
nameplate capacity is required to be recorded, reported, or used in a 
calculation.
    To ensure that the mass balance method is based on consistent 
nameplate capacity values throughout the life of the equipment, we are 
finalizing at 40 CFR 98.303(b)(9) that electrical equipment users are 
allowed to measure and revise the nameplate capacity value of any given 
piece of equipment only once, unless the nameplate capacity itself is 
likely to have changed due to changes to the equipment (e.g., 
replacement of the equipment bushings).
    To help ensure that electrical equipment users obtain accurate 
measurements of their equipment's nameplate capacities, we are 
finalizing requirements at 40 CR 98.303(b)(10) that

[[Page 31848]]

electrical equipment users must use measurement devices that meet the 
following accuracy and precision requirements when they measure the 
nameplate capacities of new and retiring equipment:
     Flow meters must be certified by the manufacturer to be 
accurate and precise to within one percent of the largest value that 
the flow meter can, according to the manufacturer's specifications, 
accurately record.
     Pressure gauges must be certified by the manufacturer to 
be accurate and precise to within 0.5 percent of the largest value that 
the gauge can, according to the manufacturer's specifications, 
accurately record.
     Temperature gauges must be certified by the manufacturer 
to be accurate and precise to within 1.0 [deg]F; and
     Scales must be certified by the manufacturer to be 
accurate and precise to within one percent of the true weight.
    Additional information on these revisions and their supporting 
basis may be found in section III.N.1. of the preamble to the 2022 Data 
Quality Improvements Proposal.
    We are finalizing at 40 CFR 98.306(r) and (s) (proposed as 40 CFR 
98.306(o) and (p)) requirements for equipment users who measure and 
adopt nameplate capacity values to report the total rated and measured 
nameplate capacities across all the equipment whose nameplate 
capacities were measured and for which the measured nameplate 
capacities have been adopted in that year.
    We are finalizing requirements in 40 CFR 98.307(b) as proposed for 
equipment users to keep records of certain identifying information for 
each piece of equipment for which they measure the nameplate capacity: 
the rated and measured nameplate capacities, the date of the nameplate 
capacity measurement, the measurements and calculations used to obtain 
the measured nameplate capacity (including the temperature-pressure 
curve and/or other information used to derive the initial and final 
temperature adjusted pressures of the equipment), and whether or not 
the measured nameplate capacity value was adopted for that piece of 
equipment.
    To clarify the mass balance methodology in 40 CFR 98.303, we are 
adding definitions for ``energized,'' ``new equipment,'' and ``retired 
equipment,'' at 40 CFR 98.308 as proposed. We are finalizing the 
definition of ``energized'' as proposed to mean ``connected through 
busbars or cables to an electrical power system or fully-charged, ready 
for service, and being prepared for connection to the electrical power 
system. Energized equipment does not include spare gas insulated 
equipment (including hermetically-sealed pressure switchgear) in 
storage that has been acquired by the facility, and is intended for use 
by the facility, but that is not being used or prepared for connection 
to the electrical power system.'' The final definition more clearly 
designates what equipment is considered to be installed and functioning 
as opposed to being in storage.
    With two minor changes, we are finalizing the proposed definition 
for ``new equipment.'' ``New equipment'' is defined as ``either (1) any 
gas insulated equipment, including hermetically-sealed pressure 
switchgear, that is not energized at the beginning of the reporting 
year but is energized at the end of the reporting year, or (2) any gas 
insulated equipment other than hermetically-sealed pressure switchgear 
that has been transferred while in use, meaning it has been added to 
the facility's inventory without being taken out of active service 
(e.g., when the equipment is sold to or acquired by the facility while 
remaining in place and continuing operation).'' Similarly, we are 
finalizing the definition for ``retired equipment'' with two minor 
changes. ``Retired Equipment'' is defined as ``either (1) any gas 
insulated equipment, including hermetically-sealed pressure switchgear, 
that is energized at the beginning of the reporting year but is not 
energized at the end of the reporting year, or (2) any gas insulated 
equipment other than hermetically-sealed pressure switchgear that has 
been transferred while in use, meaning it has been removed from the 
facility's inventory without being taken out of active service (e.g., 
when the equipment is acquired by a new facility while remaining in 
place and continuing operation).'' The proposed definitions both 
included two sentences, where the first sentence specified that the 
equipment changed from ``not energized'' to ``energized'' (or vice 
versa), and the second sentence preceded the phrase ``that has been 
transferred while in use'' with ``This includes.'' Upon review of the 
proposed definitions, we realized that they could lead to confusion 
because equipment that is transferred while in use does not change from 
``not energized'' to ``energized'' or vice versa, and therefore cannot 
be ``included'' in the sets of equipment that change from ``not 
energized'' to ``energized'' or vice versa. We therefore replaced 
``This includes'' with ``or.'' We also realized that including 
hermetically-sealed pressure switchgear in equipment that is 
transferred while in use would trigger requirements to inventory the 
acquired (new) or disbursed (retired) hermetically-sealed pressure 
switchgear for purposes of the mass balance calculation (equation DD-4) 
and the reporting requirements at 40 CFR 98.306(a)(2) and (4). We did 
not intend to trigger these requirements for hermetically sealed 
pressure equipment that is transferred during use. Such requirements 
would be inconsistent with the intent and effect of the current 
provision at 40 CFR 98.306(a)(1), which excludes existing hermetically-
sealed pressure switchgear from the requirement to report the existing 
nameplate capacity total at the beginning of the year. We therefore 
excepted hermetically sealed switchgear from equipment that is 
transferred while in use in both definitions. With these minor changes, 
the definitions clarify how the terms ``new'' and ``retired'' should be 
interpreted for purposes of equation DD-3.
b. Revisions To Streamline and Improve Implementation for Subpart DD
    The EPA is finalizing several revisions to subpart DD to streamline 
requirements. First, we are revising the applicability threshold of 
subpart DD at 40 CFR 98.301 largely as proposed, in order to align with 
revisions to include additional F-GHGs in subpart DD. However, as 
discussed above, insulating gases with weighted average GWPs less than 
or equal to 1 will remain excluded from reporting under subpart DD. We 
are replacing the existing nameplate capacity threshold with an 
emissions threshold of 25,000 mtCO2e per year of F-GHGs that 
are components of reportable insulating gases (i.e., insulating gases 
whose weighted average GWPs, as calculated in equation DD-3, are 
greater than one (1)). To calculate their F-GHG emissions for 
comparison with the threshold, electrical equipment users will use one 
of two new equations finalized in subpart DD at 40 CFR 98.301, 
equations DD-1 and DD-2. The equations explicitly include not only the 
nameplate capacity of the equipment but also an updated default 
emission factor and the GWP of each insulating gas.
    We are also finalizing revisions to the existing calculation, 
monitoring, and reporting requirements of subpart DD to require 
reporting of additional F-GHGs beyond SF6 and PFCs that are 
components of reportable insulating gases. The new equations DD-1 and 
DD-2 that we are finalizing for the applicability threshold require 
potential

[[Page 31849]]

reporters to account for the total nameplate capacity of all equipment 
containing reportable insulating gases (located on-site and/or under 
common ownership or control), including equipment containing F-GHG 
mixtures, and multiply by the weight fraction of each F-GHG (for gas 
mixtures), the GWP for each F-GHG, and an emission factor of 0.10 
(representing an emission rate of 10 percent).
    We are finalizing harmonizing changes in multiple sections of 
subpart DD to renumber equation DD-1 and maintain cross-references to 
the equation. We are also finalizing revisions to the existing 
threshold in 40 CFR 98.301 and table A-3 to subpart A (General 
Provisions). Additional information on these revisions and their 
supporting basis may be found in section III.N.2. of the preamble to 
the 2022 Data Quality Improvements Proposal.
    Finally, we are removing an outdated monitoring provision at 40 CFR 
98.304(a), which reserves a prior requirement for use of BAMM that 
applied solely for RY2011.
2. Summary of Comments and Responses on Subpart DD
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart DD. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart DD.
a. Comments on Revisions To Improve the Quality of Data Collected for 
Subpart DD
    Comment: One commenter asked for clarification regarding whether 
the equipment user needs to account for insulating gas remaining inside 
gas-insulated equipment (GIE) that are transferred to another entity 
(vendor) for repair or salvage. The commenter asserted that since the 
equipment is leaving the inventory with gas inside, it should be 
counted as both retired equipment and a gas disbursement. The commenter 
suggested the ``Disbursements'' term in equation DD-3 be modified to 
include similar language to the ``Acquisitions'' term, to clarify that 
gas inside equipment that is transferred to another entity for repair 
or salvage, in addition to equipment that is sold, counts as a 
disbursement.
    Response: The EPA agrees with the commenter and is revising the 
``Disbursements'' term in equation DD-3 (being finalized as equation 
DD-4) to account for gas ``transferred'' as well as ``sold'' to ``other 
entities.'' As discussed in section III.Q.1. of this preamble, we are 
making a number of clarifications to the ``Acquisitions'' and 
``Disbursements'' terms in equation DD-4 to accommodate the full range 
of possible acquisitions and disbursements by electric power systems, 
which will improve the accuracy and completeness of equation DD-4 and 
the associated reporting and recordkeeping requirements.
    Comment: One commenter suggested that the EPA revise the nameplate 
capacity adjustment text as follows: first, to remove the word 
``covered'' prior to ``insulating gas'' in 40 CFR 98.303(b)(4)(ii)(A), 
since ``covered'' is not included in the EPA's definition of insulating 
gas.
    Response: The EPA agrees with the commenter and is revising 40 CFR 
98.303(b)(4)(ii)(A) as suggested to reflect the language which is used 
in the definitions and to minimize confusion. As discussed in section 
III.Q.1. of this preamble, we are introducing the term ``reportable 
insulating gas'' to distinguish between insulating gas that is included 
in subpart DD (``reportable'') because it has a weighted average GWP 
greater than 1 and insulating gas that is not reportable because it has 
a weighted average GWP of 1 or less.
    Comment: Two commenters suggested the EPA change the language in 40 
CFR 98.303(b)(5)(ii), which was proposed as a requirement to ``convert 
the initial system pressure to a temperature-compensated initial system 
pressure by using the temperature/pressure curve for that insulating 
gas.'' The commenters stated that the temperature/pressure curve is not 
intended for conversions of initial system pressure to temperature-
compensated pressure. The commenters suggested that the requirement 
should be to compare the measured initial system pressure and vessel 
temperature to the equipment manufacturer's temperature-pressure curve 
specific for the equipment to confirm the equipment is at the proper 
operating pressure, prior to recovery of the insulating gas. One 
commenter recommended two options for measuring initial gas pressure: 
(1) use external pressure and temperature gauges according to 40 CFR 
98.303(b)(5)(i); or (2) if an integrated temperature-compensated gas 
pressure gauge was used for the initial gas fill and to monitor and 
maintain the gas at the proper operating pressure over the service life 
of the circuit breaker, use the same gauge to determine whether the 
circuit breaker is at the proper operating pressure.
    Response: The EPA agrees with the commenters regarding the language 
at 40 CFR 98.303(b)(5)(ii) and is finalizing the requirement as 
follows: ``Compare the initial system pressure and temperature to the 
equipment manufacturer's temperature/pressure curve for that equipment 
and insulating gas.'' Regarding allowing use of an integrated 
temperature-compensated gas pressure gauge, use of such a gauge is 
allowed if the gauge is certified by the gauge manufacturer to be 
accurate and precise to within 0.5 percent of the largest value that 
the gauge can, according to the manufacturer's specifications, 
accurately record. It is EPA's understanding that many gauges that are 
built into the electrical equipment do not meet these accuracy and 
precision requirements. However, if they do, the rule does not prohibit 
their use in nameplate capacity measurements.
    Comment: One commenter objected to the proposed requirement to 
recover the insulating gas to a blank-off pressure not greater than 3.5 
Torr during the nameplate capacity measurement. The commenter noted 
that not all facilities own gas carts capable of reaching 3.5 Torr, 
and, for some GIE, that level of pressure is not necessary for an 
accurate reading. The commenter recommended that the GIE recovery be 
performed to allow for 99.1 percent or greater recovery of the 
insulating gas.
    Response: As discussed above, the EPA is finalizing a requirement 
that facilities measuring the nameplate capacity of their equipment 
recover the gas to a pressure of at most 5 psia (258.6 Torr). This will 
accommodate gas carts that are not capable of reaching 3.5 Torr. To 
ensure that the gas remaining in the equipment at pressures above 3.5 
Torr is accounted for, facilities that recover the gas to a pressure 
between 5 psia and 3.5 Torr will be required to use the mathematical 
adjustment approach (equation DD-5) to calculate the full nameplate 
capacity. As discussed in the preamble to the proposed rule, the EPA 
estimates that 0.1 percent of the full and proper charge of insulating 
gas would remain in the equipment at 3.5 Torr (assuming that a full and 
proper charge has a pressure of 3800 Torr), a negligible fraction. 
However, the fraction of gas remaining after recovery of 99.1 percent 
of the gas, 0.9%, is not negligible, but represents a significant 
systematic underestimate compared to the 2% tolerance for nameplate 
capacity measurements. Since it is straightforward to correct for this 
systematic underestimate by using the

[[Page 31850]]

mathematical adjustment approach, we are requiring use of equation DD-5 
in such situations.
    Comment: One commenter representing manufacturers of electrical 
equipment recommended that after insulating gas was added to a piece of 
electrical equipment, facilities should allow at least 24 hours to 
allow the gas to condition itself to its container in order to confirm 
the correct density has been met.
    Response: The EPA is adding a requirement to 40 CFR 
98.303(b)(4)(ii) that facilities follow the procedure specified by the 
electrical equipment manufacturer to ensure that the measured 
temperature accurately reflects the temperature of the insulating gas, 
e.g., by measuring the insulating gas pressure and vessel temperature 
after allowing appropriate time for the temperature of the transferred 
gas to equilibrate with the vessel temperature. This allows for the 
possibility that some electrical equipment, e.g., electrical equipment 
with smaller charge sizes, may require less than 24 hours for the 
insulating gas temperature to equilibrate with the temperature of the 
vessel. Because achieving the correct density of the insulating gas in 
the equipment is important to the proper functioning of the equipment, 
the guidance provided by the equipment manufacturer should be 
sufficient to ensure that the appropriate density is achieved for 
purposes of the nameplate capacity measurement.
    Comment: Commenters representing electrical equipment users and 
manufacturers provided input on the use of mass flow meters to measure 
the nameplate capacities of new and retiring electrical equipment. One 
commenter provided recommended edits to the proposed text to add 
requirements to ensure that a minimum gas flow is maintained while 
measuring the mass of insulating gas being added to new equipment. The 
commenter stated that to ensure that the flowmeter was properly 
configured for its application, the maximum and minimum flow rates of 
the meter, as well as the displacement of the pumps and compressors on 
the gas cart being used, must be taken into consideration. The 
commenter added that, in general, mass flow meters designed for high 
flow applications will not be suitable for low flow conditions and 
meters designed for low flow applications will not be suitable for high 
flow conditions. This commenter also recommended adding the use of an 
in-calibration cylinder scale as an alternative option for measuring 
the gas transferred during the equipment filling process. Two 
commenters recommended removing the option to use a mass flow meter to 
measure the mass of insulating gas recovered from retiring equipment 
due to the potential for errors when a mass flow meter is used in this 
process. The commenters stated that use of a mass flow meter to measure 
the insulating gas recovered is not recommended since a mass flow meter 
does not accurately measure gas at low flow rates. Instead, the 
commenters recommended that the gas container weighing method should be 
used to accurately measure the total weight of insulating gas recovered 
from the equipment. One commenter added that the process of weighing 
all gas removed from a GIE and transferred into a cylinder includes 
weighing all the gas trapped in hoses and in gas cart, which would not 
be accounted for by the flow meter; the commenter pointed out that the 
gas (trapped in hoses and in the gas cart) would need to be moved into 
cylinders to be accurately weighed with a cylinder scale.
    Response: After consideration of these comments, the EPA is 
finalizing the proposed provisions for measuring the nameplate 
capacities of new and retiring equipment with two changes. First, we 
are requiring that facilities that use mass flow meters to measure the 
mass of insulating gas added to new equipment must keep the mass flow 
rate within the range specified by the mass flow meter manufacturer to 
assure an accurate and precise mass flow meter reading. Second, we are 
removing the option to use mass flow meters to measure the quantity of 
gas recovered from retiring equipment. We have analyzed the impact of 
the uncertainty of flowmeters at low flow rates on overall nameplate 
capacity measurements, and we have concluded that this impact may lead 
to large errors under some circumstances. As noted by the commenters, 
the relative error for flowmeters can increase when the flowmeter is 
used to measure mass flow rates below a certain fraction of the maximum 
full-scale value, and the mass flow rate will gradually decline as the 
insulating gas is transferred from the container to the equipment or 
vice versa, reducing the density of the gas inside the source vessel. 
For measuring the quantity of insulating gas added to new equipment, 
this issue can be addressed by requiring that the mass flow rate be 
kept within the range specified by the mass flow meter manufacturer, 
which can be accomplished by, e.g., switching to a full container when 
the density of the insulating gas in the current container falls below 
the minimum level. However, for measuring the quantity of insulating 
gas recovered from retiring equipment, the insulating gas is being 
transferred from the equipment itself, and the recovery process 
therefore inevitably lowers the mass flow rate below the minimum level. 
For this reason, we are not taking final action on the option to use 
flowmeters to measure the quantity of insulating gas recovered from 
retiring equipment.
    In our analysis of this issue, we reviewed our proposal at 40 CFR 
98.303(b)(10) that mass flow meters must be accurate and precise to 
within one percent of the largest value that the flow meter can, 
according to the manufacturer's specifications, accurately record, 
i.e., the maximum full-scale value. This means that the relative error 
of the flowmeter could rise hyperbolically from one percent of the 
measured value (when the measured value equals the maximum value) to 
much higher levels at lower flow rates, e.g., 2 percent of the flow 
rate at half the maximum, 4 percent of the flow rate at one quarter of 
the maximum, 10 percent of the flow rate at one tenth the maximum, etc. 
These rising relative errors lead to overall errors in the mass flow 
measurement that are far above one percent. Even if the flow meter is 
accurate to within one percent of the measured value over a ten-fold 
range of flow rates, errors at lower flow rates can be significant. In 
an example provided to us by a company that provides insulating gas 
recovery equipment (gas carts) and insulating gas recovery services to 
electric power systems, the relative error of the measurement of the 
flow rate rose by a factor of five when the flow rate fell below 10 
percent of the maximum full-scale value. If the error of a flowmeter 
climbed from 1 percent to 5 percent when the flow rate fell below 10 
percent of the maximum full-scale value, the measurement of the total 
mass recovered would have a maximum uncertainty of 1.4 percent, which 
can result in overall errors above 2 percent in the nameplate capacity 
measurement as a whole (accounting also for the uncertainties of 
measured pressures, etc.).
    Regarding one commenter's recommendation that we allow weigh scales 
to be used to measure the quantity of gas filled into new equipment, we 
are finalizing our proposal at 40 CFR 98.303(b)(4)(ii)(A) to allow use 
of weigh scales for this measurement.
    Comment: Two commenters requested the EPA remove the term 
``precise'' from proposed 40 CFR 98.303(b)(10). Both commenters 
stressed that accuracy is more important. One commenter stated that 
equipment certified to be accurate

[[Page 31851]]

and precise may be difficult to find, and another additionally asserted 
there is little value in precision.
    Response: In the final rule, we are finalizing as proposed the 
accuracy and precision requirements for gauges, flow meters, and weigh 
scales used to measure nameplate capacities. To obtain an accurate 
measurement of the nameplate capacity of a piece of equipment, 
measurement devices must be both accurate and precise. As discussed in 
the technical support document for the proposed rule,\18\ the term 
``accurate'' indicates that multiple measurements will yield an average 
that is near the true value, while the term ``precise'' indicates that 
multiple measurements will yield consistent results. A measurement 
device that is accurate without being precise may show inconsistent 
results from measurement to measurement, and these individual 
inconsistent results may be significantly different from the true value 
even if their average is not. Since measurements of nameplate capacity 
are generally expected to be taken only once for a particular piece of 
equipment, the devices on which the individual measurements are taken 
must be both accurate and precise for the measurements to yield results 
that are near the true values.
---------------------------------------------------------------------------

    \18\ See ``Technical Support for Proposed Revisions to Subpart 
DD (2021),'' available in the docket to this rulemaking, Docket ID. 
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Comment: One commenter suggested redefining the definition of 
``insulating gas'' to including any gas with a GWP greater than one (1) 
and not any fluorinated GHG or fluorinated GHG mixture. The commenter 
urged that the proposed definition ignores other potential gases that 
may come onto the market that are not fluorinated but still have a GWP. 
The commenter stated that defining insulating gas to include any gas 
with a GWP greater than 1 used as an insulating gas and/or arc 
quenching gas in electrical equipment would mirror the threshold 
implemented by the California Air Resources Board and would provide 
consistency for reporters across Federal and State reporting rules.
    Response: In the final rule, the EPA is not requiring electric 
power systems to track or report emissions of insulating gases with 
weighted average 100-year GWPs of one or less. Based on a review of the 
subpart DD data submitted to date, the EPA has concluded that excluding 
insulating gases with weighted average GWPs of one or less from 
reporting under subpart DD will have little effect on the accuracy or 
completeness of the GWP-weighted totals reported under subpart DD or 
under the GHGRP generally. Between 2011 and 2021, the highest emitting 
facilities reporting under subpart DD reported SF6 emissions 
ranging from 8 to 23 mt (unweighted) or 190,000 to 540,000 
mtCO2e. Over the same period, total emissions across all 
facilities have ranged from 96 to 171 mt (unweighted) or 2.3 to 4.1 
million mtCO2e. At GWPs of one, these weighted totals would 
be equivalent to the unweighted quantities reported, which constitute 
approximately 0.004% (1/23,500) of the GWP-weighted totals. This does 
not account for the fact that for the first few years it is sold, 
equipment containing insulating gases with weighted average GWPs of one 
or less will make up a small fraction of the total nameplate capacity 
of the electrical equipment in use. (Electrical equipment has a 
lifetime of about 40 years, so only a small fraction of the total stock 
of equipment is retired and replaced each year.) Even in a worst-case 
scenario where the annual emission rate of the equipment containing a 
very low-GWP insulating gas was assumed to equal the total nameplate 
capacity of all the equipment installed (implying an emission rate of 
100 percent, higher than any ever reported under the GHGRP), the total 
GWP-weighted emissions reported under subpart DD would be considerably 
smaller than those reported under any other subpart: total unweighted 
nameplate capacities reported across all facilities to date have ranged 
between 4,847 and 6,996 mt. At GWPs of 1, these totals would fall under 
the 15,000 and 25,000 mtCO2e quantities below which 
individual facilities are eventually allowed to exit the program under 
the off-ramp provisions, as applicable.
    To monitor trends in the replacement of SF6 by 
insulating gases with weighted average GWPs less than one, the EPA will 
continue to track supplies of such insulating gases under subparts OO 
and QQ and will track deliveries of such insulating gases in equipment 
or containers under subpart SS.
b. Comments on Revisions To Streamline and Improve Implementation for 
Subpart DD
    Comment: One commenter supported the proposed threshold for subpart 
DD but wanted the EPA to clarify that reporters that do not think they 
will fall below the revised reporting threshold or are not otherwise 
using F-GHGs other than SF6 do not need to recalculate their 
emissions to show they must report.
    Response: The applicability threshold is for determining whether 
entities must initially begin reporting to the GHGRP. Facilities that 
have reported have calculated their emissions more precisely using the 
mass balance approach. If those calculations have shown that they are 
eligible to exit the program under the off-ramp provisions of subpart A 
of part 98 (40 CFR 98.2(i)), they do not need to report again unless 
facility emissions exceed 25,000 mtCO2e. On the other hand, 
if the calculations have shown that the facility does not meet the 
existing off-ramp conditions to exit the program, they must continue 
reporting regardless of the results of the threshold calculation at 40 
CFR 98.301.

R. Subpart FF--Underground Coal Mines

    We are finalizing the amendments to subpart FF of part 98 
(Underground Coal Mines) as proposed. The EPA received no comments 
objecting to the proposed revisions to subpart FF; therefore, there are 
no changes from the proposal to the final rule. The EPA is finalizing 
two technical corrections to: (1) correct the term ``MCFi'' 
in equation FF-3 to subpart FF to revise the term ``1-
(fH2O)1'' to ``1-(fH2O)i'', and (2) to correct 40 
CFR 98.326(t) to add the word ``number'' after the word 
``identification'' to clarify the reporting requirement. Additional 
rationale for these amendments is available in the preamble to the 2022 
Data Quality Improvements Proposal.

S. Subpart GG--Zinc Production

    This section discusses the final revisions to subpart GG. We are 
finalizing amendments to subpart GG of part 98 (Zinc Production) as 
proposed. The EPA received only supportive comments for the proposed 
revisions to subpart GG. See the document ``Summary of Public Comments 
and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart GG. Additional rationale 
for these amendments is available in the preamble to the 2022 Data 
Quality Improvements Proposal.
    The EPA is finalizing one revision to add a reporting requirement 
at 40 CFR 98.336(a)(6) and (b)(6) for the total amount of electric arc 
furnace (EAF) dust annually consumed by all Waelz kilns at zinc 
production facilities. The final data elements will only require 
segregation and reporting of the mass of EAF dust consumed for all 
kilns. These requirements apply to reporters using either the CEMS 
direct measurement or mass balance calculation

[[Page 31852]]

methodologies. Reporters currently collect information on the EAF dust 
consumed on a monthly basis as part of their existing operations as a 
portion of the inputs to equation GG-1 to subpart GG; reporters will 
only be required to sum all EAF dust consumed on a monthly basis for 
each kiln and then for all kilns at the facility for reporting and 
entering the information into e-GGRT. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal. We are also finalizing as proposed 
confidentiality determinations for new data elements resulting from the 
final revisions to subpart GG, as described in section VI. of this 
preamble.

T. Subpart HH--Municipal Solid Waste Landfills

    We are finalizing several amendments to subpart HH of part 98 
(Municipal Solid Waste Landfills) as proposed. In some cases, we are 
finalizing the proposed amendments with revisions. In other cases, we 
are not taking final action on the proposed amendments. Section 
III.T.1. of this preamble discusses the final revisions to subpart HH. 
The EPA received several comments on proposed subpart HH revisions 
which are discussed in section III.T.2. of this preamble. We are also 
finalizing as proposed confidentiality determinations for new data 
elements resulting from the final revisions to subpart HH, as described 
in section VI. of this preamble.
1. Summary of Final Amendments to Subpart HH
    This section summarizes the final amendments to subpart HH. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart HH can be found in this section and 
section III.T.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.
    The EPA is finalizing several revisions to subpart HH to improve 
the quality of data collected under the GHGRP. First, the EPA is 
finalizing revisions to update the factors used in modeling 
CH4 generation from waste disposed at landfills in table HH-
1 to subpart HH. As explained in the 2022 Data Quality Improvements 
Proposal, subpart HH uses a model to estimate CH4 generation 
that considers the quantity of MSW landfilled, the degradable organic 
carbon (DOC) content of that MSW, and the first order decay rate (k) of 
the DOC. Table HH-1 to subpart HH provides DOC and k values that a 
reporter must use to calculate their CH4 generation based on 
the different categories of waste disposed at that landfill and the 
climate in which the landfill is located. The EPA previously conducted 
a multivariate analysis of data reported under subpart HH to estimate 
updated DOC and k values for each waste characterization option. 
Details of this analysis are available in the memorandum from Meaghan 
McGrath, Kate Bronstein, and Jeff Coburn, RTI International, to Rachel 
Schmeltz, EPA, ``Multivariate analysis of data reported to the EPA's 
Greenhouse Gas Reporting Program (GHGRP), Subpart HH (Municipal Solid 
Waste Landfills) to optimize DOC and k values,'' (June 11, 2019), 
available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424. The EPA is finalizing the following changes as proposed:
     For the Bulk Waste option, amending the bulk waste DOC 
value in table HH-1 from 0.20 to 0.17.
     For the Modified Bulk Waste option, for bulk MSW waste 
without inerts and (C&D) waste, amending the DOC value from 0.31 to 
0.27.
     For the Waste Composition option, adding a DOC for 
uncharacterized MSW of 0.32, and revising 40 CFR 98.343(a)(2) to 
reference using this uncharacterized MSW DOC value rather than the bulk 
MSW value for waste materials that could not be specifically assigned 
to the streams listed in table HH-1 for the Waste Composition option.
    The EPA is also revising the default decay rate values in table HH-
1 for the Bulk Waste option and the Modified Bulk MSW option and adding 
k value ranges for uncharacterized MSW for the Waste Composition 
Option. The final k values, which have been revised from those 
proposed, are shown in table 4 of this preamble. The revised defaults 
represent the average optimal k values derived through an additional 
optimization analysis conducted in response to comments where the bulk 
waste DOC value was set to the revised value of 0.17 and optimal k 
values were determined for each precipitation category.

                    Table 4--Revised Default k Values
------------------------------------------------------------------------
               Factor                 Subpart HH default       Units
------------------------------------------------------------------------
k values for Bulk Waste option and                        ..............
 Modified Bulk MSW option.
k (precipitation plus recirculated   0.033..............  yr-1.
 leachate <20 inches/year).
k (precipitation plus recirculated   0.067..............  yr-1.
 leachate 20-40 inches/year).
k (precipitation plus recirculated   0.098..............  yr-1.
 leachate >40 inches/year).
k value range for Waste Composition                       ..............
 option.
k (uncharacterized MSW)............  0.033 to 0.098.....  yr-1.
------------------------------------------------------------------------

    The revisions to the DOC and k values in table HH-1 reflect the 
compositional changes in materials that are disposed at landfills. 
These updated factors will allow MSW landfills to more accurately model 
their CH4 generation. We are also clarifying in the final 
rule that starting in RY2025 these new DOC and k values are to be 
applied for disposal years 2010 and later, consistent with when the 
compositional changes occurred. Additional information on these 
revisions and their supporting basis may be found in section III.Q. of 
the preamble to the 2022 Data Quality Improvements Proposal and in the 
memorandum ``Revised Analysis and Calculation of Optimal k Values for 
Subpart HH MSW Landfills Using a 0.17 DOC Default and Timing 
Considerations'' included in Docket ID. No. EPA-HQ-OAR-2019-0424.
    We are also finalizing, as proposed, revisions to account for 
CH4 emission events that are not well quantified under the 
GHGRP including: (1) a poorly operating or non-operating gas collection 
system; and (2) a poorly operating or non-operating destruction device. 
The EPA is finalizing, as proposed, revisions and additions to address 
these scenarios as follows:
     Revising equations HH-7 and HH-8 to more clearly indicate 
that the ``fRec'' term is dependent on the gas collection 
system, to clarify how the equation

[[Page 31853]]

applies to landfills that may have more than one gas collection system 
and may have multiple measurement locations associated with a single 
gas collection system.
     Clarifying in ``fRec'' that the recovery system 
operating hours only include those hours when the system is operating 
normally. Facilities should not include hours when the system is shut 
down or when the system is poorly operating (i.e., not operating as 
intended). Poorly operating systems can be identified when pressure, 
temperature, or other parameters indicative of system performance are 
outside of normal variances for a significant portion of the system's 
gas collection wells.
     For equations HH-6, HH-7, and HH-8, revising the term 
``fDest'' to clarify that the destruction device operating 
hours exclude periods when the destruction device is poorly operating. 
Facilities should only include those periods when flow was sent to the 
destruction device and the destruction device was operating at its 
intended temperature or other parameter that is indicative of effective 
operation. For flares, periods when there is no flame present must be 
excluded from the annual operating hours.
    Following consideration of comments received, the EPA is finalizing 
two minor clarifications of the term ``fDest,n'' in 
equations HH-7 and HH-8. First, we are removing the redundant phrase 
``as measured at the nth measurement location.'' Second, we are 
removing the word ``pilot'' to clarify that for flares used as a 
destruction device, the annual operating hours must exclude any period 
in which no flame is present, either pilot or main. These changes 
account for variances in flare operation, e.g., flares which may only 
use a pilot on startup. See section III.T.2. of this preamble for 
additional information on related comments and the EPA's response.
    In the 2023 Supplemental Proposal, we proposed that facilities that 
conduct surface-emissions monitoring must use that data and correct the 
emissions calculated in equations HH-6, HH-7, and HH-8 to account for 
excess emissions when the measured surface methane concentration 
exceeded 500 ppm based on a correction term added to those equations. 
We also proposed for facilities not conducting surface-emissions 
monitoring to use collection efficiencies that are 10-percentage points 
lower than the historic collection efficiencies in table HH-3 to 
subpart HH. Following consideration of comments received, we are not 
taking final action on the surface-emissions monitoring correction term 
that was proposed. Instead, we are finalizing the proposed lower 
collection efficiencies in table HH-3 to subpart HH, but applying the 
reduced collection efficiencies for all reporters under subpart HH. See 
section III.T.2. of this preamble for additional information on related 
comments and the EPA's response.
    The EPA is also finalizing several revisions to the reporting 
requirements for subpart HH, including more clearly identifying 
reporting elements associated with each gas collection system, each 
measurement location within a gas collection system, and each control 
device associated with a measurement location. First, we are finalizing 
revisions to landfills with gas collection systems consistent with the 
proposed revisions in the methodology, i.e., to separately require 
reporting for each gas collection systems and for each measurement 
location within a gas collection system. We are requiring, for each 
measurement location that measures gas to an on-site destruction 
device, certain information be reported about the destruction device, 
including: type of destruction device; the total annual hours where gas 
was sent to the destruction device; a parameter indicative of effective 
operation, such as the annual operating hours where active gas flow was 
sent to the destruction device and the destruction device was operating 
at its intended temperature; and the fraction of the recovered methane 
reported for the measurement location directed to the destruction 
device. We are also requiring reporting of identifying information for 
each gas collection system, each measurement location within a gas 
collection system, and each destruction device. We are also finalizing 
reporting requirements for landfills with gas collection systems to 
indicate the applicability of the NSPS (40 CFR part 60, subparts WWW or 
XXX), state plans implementing the EG (40 CFR part 60, subparts Cc or 
Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO).
    In the 2023 Supplemental Proposal, the EPA also sought comment on 
how other CH4 monitoring technologies, e.g., satellite 
imaging, aerial measurement, vehicle-mounted mobile measurement, or 
continuous sensor networks, might enhance subpart HH emissions 
estimates. The EPA did not propose, and therefore is not taking final 
action on, any amendments to subpart HH to this effect. However, the 
EPA did seek comment on the availability of existing monitoring 
technologies, and regulatory approaches and provisions necessary to 
incorporate such data into subpart HH for estimating annual emissions. 
We will continue to review the comments received along with other 
studies and may amend subpart HH to allow the incorporation of 
additional measurement or monitoring methodologies in the future.
2. Summary of Comments and Responses on Subpart HH
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart HH. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart HH.
    Comment: Numerous commentors stated that methane detection 
technology, specifically top-down direct measurement from aerial 
studies, has greatly improved the ability to observe and quantify 
emissions from landfills (e.g., Krautwurst, et al., 2017; Cusworth, et 
al., 2022).^{19 20} Some commenters noted that, among several 
studies in California, Maryland, Texas, and Indiana, there are 
discrepancies between observed data collected from these new detection 
technologies and the estimated emissions from the models that the EPA 
currently uses. Several commenters pointed to a recent study (Nesser, 
et al., 2023) using satellite data that highlighted that at 33 of 70 
landfills studied, U.S. GHG Inventory landfill emissions are 
underestimated by 50 percent when compared to the current top-down 
approaches.\21\ These discrepancies indicate methane emissions from 
landfills may be considerably higher than currently recorded. Some 
commenters stated that advanced methane monitoring technology has 
improved significantly in effectiveness and cost, and provided specific 
input regarding advanced methane monitoring technologies available for 
landfills and how their data might enhance subpart

[[Page 31854]]

HH emissions reporting. The commenters pointed to both screening and 
close-range technologies that would be beneficial for pinpointing leaks 
or emission sources, and outlined several technologies including 
satellite imaging, aerial measurements, vehicle-mounted mobile 
measurement, and continuous sensor networks. The commenters recommended 
comprehensive monitoring with both screening and close-range 
technologies to provide full coverage. The commenters suggested the use 
of these technologies to catch large emission events that are not 
accounted for in the existing reporting requirements. Commenters noted 
that the EPA could review submitted reports and activity data to 
determine how to best quantify the observed large release events as 
compared to annual reported emissions (e.g., updating fRec 
or fDest values to account for periods of downtime or poor 
performance not captured that contributed to a large discrepancy).
---------------------------------------------------------------------------

    \19\ Krautwurst, S., et al., (2017). ``Methane emissions from a 
Californian landfill, determined from airborne remote sensing and in 
situ measurements.'' Atmos. Meas. Tech. 10:3429-3452. https://doi.org/10.5194/amt-10-3429-2017.
    \20\ Cusworth, D., et al., (2020). ``Using remote sensing to 
detect, validate, and quantify methane emissions from California 
solid waste operations.'' Environ. Res. Lett. 15: 054012.
    \21\ Nesser, H., et al. 2023. High-resolution U.S. methane 
emissions inferred from an inversion of 2019 TROPOMI satellite data: 
contributions from individual states, urban areas, and landfills, 
EGUsphere [preprint], https://doi.org/10.5194/egusphere-2023-946, 
2023.
---------------------------------------------------------------------------

    Other commenters recommended that the EPA create a mechanism under 
subpart HH for receiving and considering third-party observational data 
that the EPA could then use to revise reported emissions as necessary. 
Some commenters suggested the EPA base a threshold for these sources of 
100 kg/hour. Commenters also recommended setting assumptions for the 
duration of the emissions similar to those proposed for subpart W of 
part 98 (Petroleum and Natural Gas Systems). Some commenters suggested 
the EPA should embrace for landfills the same tiered methane emissions 
monitoring approach as is utilized in its proposed rulemaking for the 
oil and gas sector. Commenters also suggested a tiered approach that 
combines continuous monitoring ground systems with periodic remote 
sensing along with approaches for translating methane concentrations 
from top-down sources to source-specific emission rates. Commenters 
urged that the sooner the EPA can move toward top-down or facility-wide 
measurement of emissions for reporting or validation of reported 
values, the sooner reported and measured emissions would be 
reconcilable and verifiable. A few commenters also recommended that the 
EPA facilitate the flow of information from other agencies (the 
National Aeronautics and Space Administration (NASA), National Oceanic 
and Atmospheric Administration (NOAA), National Institute of Standards 
and Technology (NIST), and U.S. Department of Energy (DOE)), third 
parties, and operators to find and mitigate plumes faster.
    Several commenters provided recommendations for additional 
reporting requirements such as gas collection and capture system (GCCS) 
type and design, destruction device type and characteristics, 
monitoring technologies, site cover type, construction periods, and 
compliance issues which may relate to closures of control devices.
    Response: The EPA agrees that recent aerial studies indicate 
methane emissions from landfills may be considerably higher than 
bottom-up emissions reported under subpart HH for some landfills. 
Emissions may be considerably higher due to emissions from poorly 
operating gas collection systems or destruction devices and leaking 
cover systems. The supplemental proposal included revisions to the 
monitoring and calculation methodologies in subpart HH to account for 
these scenarios. In particular, proposed equations HH-6, HH-7, and HH-8 
included modifications to incorporate direct measurement data collected 
from methane surface-emissions monitoring. In the supplemental 
proposal, we also requested information about other direct measurement 
technologies and how their data may enhance emissions reporting under 
subpart HH. We received many responses to our request. Based on the 
comments received, we are not taking final action at this time 
regarding the incorporation of other direct measurement technologies 
for the following reasons. First, most top-down, facility measurements 
are taken over limited durations (a few minutes to a few hours) 
typically during the daylight hours and limited to times when specific 
meteorological conditions exist (e.g., no cloud cover for satellites; 
specific atmospheric stability and wind speed ranges for aerial 
measurements). These direct measurement data taken at a single moment 
in time may not be representative of the annual CH4 
emissions from the facility, given that many emissions are episodic. If 
emissions are found during a limited duration sampling, that does not 
necessarily mean they are present for the entire year. And if emissions 
are not found during a limited duration sampling, that does not mean 
significant emissions are not occurring at other times. Extrapolating 
from limited measurements to an entire year therefore creates risk of 
either over or under counting actual emissions. Second, while top-down 
measurement methods, including satellite and aerial methods, have 
proven their ability to identify and measure large emissions events, 
their detection limits may be too high to detect emissions from sources 
with relatively low emission rates or that are spread across large 
areas, which is common for landfills.\22\ This is likely why only seven 
percent of the landfills in the Duren, et al. (2019) study had 
detectable emissions. The EPA will continue to review additional 
information on existing and advanced methodologies and new literature 
studies, and consider ways to effectively incorporate these methods and 
data in future revisions under subpart HH for estimating annual 
emissions.
---------------------------------------------------------------------------

    \22\ Duren, et al. 2019. ``California's methane super-
emitters.'' Nature, Vol. 575, Issue 7781, pp. 180-184, available at 
https://doi.org/10.1038/s41586-019-1720-3. Available in the docket 
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    For the oil and gas sector, the super-emitter program that allows 
third-party measurement data to be submitted was proposed under 40 CFR 
part 60, subpart OOOOb (87 FR 74702, December 6, 2022). The GHGRP 
looked to use this information, but we did not develop or propose such 
a program under the GHGRP. As such, this type of program is beyond the 
scope of the proposed rule. We will consider whether developing and 
implementing a similar super-emitter program within subpart HH of part 
98 or the overall GHGRP is appropriate under future rulemakings.
    We proposed, and are finalizing, several additional reporting 
elements including, for landfills with a gas collection system, 
information on the applicability of the NSPS (40 CFR part 60, subparts 
WWW or XXX), state plans implementing the EG (40 CFR part 60, subparts 
Cc or Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO). We 
note that several of the items suggested are already reporting 
elements. For example, we already require reporting of a description of 
the gas collection system, such as the manufacturer, capacity, and 
number of wells, which provides requested information on GCCS type and 
design. We also proposed and are finalizing reporting requirements for 
the type of destruction device. We already require reporting of cover 
type. We consider the reporting requirements to be sufficient based on 
the current methodologies used to estimate CH4 emissions. We 
will consider the need for additional reporting elements if we 
incorporate additional measurement or monitoring methodologies in 
future rulemakings.
    Comment: Several commentors expressed limited support for the 
proposed use of surface emission monitoring data to help account for

[[Page 31855]]

emissions from cover leaks. These commenters either recommended that 
the EPA use more quantitative emission measurement methods instead of 
surface-emissions monitoring or to require that the surface-emissions 
monitoring be conducted at 25-foot intervals consistent with California 
and other state requirements, and to use a lower leaks definition of 25 
parts per million volume (ppmv), rather than using the proposed 30-
meter intervals (about 98-foot intervals) with leaks defined as 
concentrations of 500 ppmv or more above background, to help ensure the 
surface-emissions monitoring identifies all leaks from the landfill's 
surface. Other commenters opposed the proposed use of a surface-
emissions monitoring correction term in equations HH-6, HH-7, and HH-8. 
One commenter noted that the correction term that the EPA proposed 
relied on one study conducted over 20 years ago at one landfill in 
Canada. This commenter cited several other studies 
^{23 24 25 26} that showed significant variability in 
correlations between surface methane concentrations and methane 
emissions and indicated that the EPA should not rely on the results of 
this limited single study. Another commenter suggested that there is 
nothing special from a technical perspective of 500 ppmv surface 
concentration that should drive a step function change in correcting 
for emissions and surface oxidation, as proposed by the EPA. This 
commenter indicated that there is already uncertainty in the gas 
collection efficiencies and that including the proposed surface methane 
concentration term simply adds to the uncertainty. The commenter 
recommended mandating the use of lower collection efficiencies when 
there is evidence of a high number of exceedances or a high surface 
methane concentration, rather than adding the surface methane 
concentration term to equations HH-6, HH-7, and HH-8. This commenter 
also cited the work of Dr. Tarek Abichou (Kormi, et al., 2017 and 2018) 
for using surface concentration measurements to estimate 
emissions.^{27 28}
---------------------------------------------------------------------------

    \23\ Abichou, T., J. Clark, and J. Chanton. 2011. ``Reporting 
central tendencies of chamber measured surface emission and 
oxidation.'' Waste Management, 31: 1002-1008. https://doi.org/10.1016/j.wasman.2010.09.014.
    \24\ Abedini, A.R. 2014. Integrated Approach for Accurate 
Quantification of Methane Generation at Municipal Solid Waste 
Landfills. Ph.D. thesis, Dept. of Civil Engineering, University of 
British Columbia.
    \25\ Lando, A.T., H. Nakayama, and T. Shimaoka. 2017. 
``Application of portable gas detector in point and scanning method 
to estimate spatial distribution of methane emission in landfill.'' 
Waste Management, 59: 255-266. https://doi.org/10.1016/j.wasman.2016.10.033.
    \26\ Hettiarachchi, H., E. Irandoost, J.P. Hettiaratchi, and D. 
Pokhrel. 2023. ``A field-verified model to estimate landfill methane 
flux using surface methane concentration measurements.'' J. Hazard. 
Toxic Radioact. Waste, 27(4): 04023019. https://doi.org/10.1061/JHTRBP.HZENG-1226.
    \27\ Kormi, T., N.B.H. Ali, T. Abichou, and R. Green. 2017. 
``Estimation of landfill methane emissions using stochastic search 
methods.'' Atmospheric Pollution Research, 8(4): 597-605. https://dx.doi.org/10.1016/j.apr.2016.12.020.
    \28\ Kormi, T., et al. 2018. ``Estimation of fugitive landfill 
methane emissions using surface emission monitoring and Genetic 
Algorithms optimization.'' Waste Management 2018, 72: 313-328. 
https://dx.doi.org/10.1016/j.wasman.2016.11.024.
---------------------------------------------------------------------------

    Response: After considering comments received and reviewing 
additional studies, including those cited by the commenters, we are not 
taking final action on the proposed surface-emissions monitoring 
correction term at this time.\29\ Upon review of the literature studies 
cited by one commenter (Abichou, et al., 2011; Abidini, 2014; Lando, et 
al., 2017; Hettiarachchi, et al., 2023), we confirmed that there is 
significant variability in measured surface concentrations and methane 
emissions flux across different landfills. The proposed correction 
factor, attributed to Heroux, et al. (2010),\30\ was the smallest of 
the correlation factors found across the other cited literature studies 
we reviewed. Based on a preliminary review of the additional study 
data, a more central tendency estimate of the correction factor term 
would be four to six times higher than the correction term proposed.
---------------------------------------------------------------------------

    \29\ Irandoost, E. (2020). An Investigation on Methane Flux in 
Landfills and Correlation with Surface Methane Concentration 
(Master's thesis, University of Calgary, Calgary, Canada). Retrieved 
from https://prism.ucalgary.ca. https://hdl.handle.net/1880/111978.
    \30\ H[eacute]roux, M., C. Guy and D. Millette. 2010. ``A 
statistical model for landfill surface emissions.'' J. of the Air & 
Waste Management Assoc. 60:2, 219-228. https://doi.org/10.3155/1047-3289.60.2.219.
---------------------------------------------------------------------------

    Due to the high uncertainty in the proposed correction factor, we 
are assessing whether the correction term proposed for equations HH-6, 
HH-7, and HH-8 is the most appropriate method for developing a site-
specific correction for the overall gas collection efficiency for 
reporters under subpart HH. The approach presented by Kormi, et al. 
(2017, 2018) uses a Gaussian plume model in conjunction with surface 
methane concentration measurements to estimate emissions. This approach 
appears too complex to incorporate into subpart HH. We are also 
evaluating other direct measurement technologies for assessing more 
accurate, landfill-specific gas collection efficiencies. Therefore, we 
decided not to take final action on the proposed correction term for 
equations HH-6, HH-7, and HH-8 at this time while we consider and 
evaluate other options. The EPA will continue to review additional 
information on existing and advanced methodologies and new literature 
studies and consider ways to effectively incorporate these methods and 
data in future revisions under subpart HH for estimating annual 
emissions.
    Comment: Numerous commenters cited studies suggesting that subpart 
HH underestimates the actual methane emissions released from 
landfills.^{31 32} These commenters noted that the 
underestimation in subpart HH emissions is primarily due to high 
default gas collection efficiencies in subpart HH. Two commenters 
asserted that gas collection efficiencies over 90 percent should not be 
used. One of these commenters noted that despite its own two-year study 
indicating otherwise, the EPA uses a 95 percent collection efficiency 
for landfills with final covers.\33\ Two commenters opposed the EPA's 
use of the Maryland landfill data to support the proposed 10-percentage 
point decrease in landfill gas collection efficiencies, noting that 
these gas collection efficiencies were calculated based on modeled 
methane generation rather than actual methane emissions measurements. 
One commenter further suggested that the Maryland study was not 
properly peer-reviewed and is not suitable for use by the EPA in 
rulemaking according to the EPA's Summary of General Assessment Factors 
For Evaluating the Quality of Scientific and Technical Information 
(hereinafter referred to as ``General Assessment Factors'').\34\ The 
commenter further stated that the Maryland study is based on a small 
subset of landfills that is likely not representative of the sector and 
the EPA's reliance on that study to support a change to the default 
collection efficiency table (table HH-3

[[Page 31856]]

to subpart HH) is inappropriate and will lead to inaccurate reporting 
of GHG emissions from the sector. This commenter stated that the EPA 
should continue to rely on the gas collection efficiencies recommended 
in the Solid Waste Industry for Climate Solutions (``SWICS'') white 
paper entitled Current MSW Industry Position and State-of-the-Practice 
on LFG Collection Efficiency, Methane Oxidation, and Carbon 
Sequestration in Landfills.\35\ According to the commenter, the SWICS 
white paper is more comprehensive and relevant than the Maryland study. 
The commenters noted that the SWICS white paper is being revised and 
encouraged the EPA to delay revisions to the gas collection efficiency 
until the revised SWICS white paper is released.
---------------------------------------------------------------------------

    \31\ Oonk, H., 2012. ``Efficiency of landfill gas collection for 
methane emissions reduction.'' Greenhouse Gas Measurement and 
Management, 2:2-3, 129-145. https://doi.org/10.1080/20430779.2012.730798.
    \32\ Nesser, H., et al., 2023. ``High-resolution U.S. methane 
emissions inferred from an inversion of 2019 TROPOMI satellite data: 
contributions from individual states, urban areas, and landfills.'' 
EGUsphere [preprint], https://doi.org/10.5194/egusphere-2023-946.
    \33\ ARCADIS, 2012. Quantifying Methane Abatement Efficiency at 
Three Municipal Solid Waste Landfills; Final Report. Prepared for 
U.S. EPA, Office of Research and Development, Research Triangle 
Park, NC. EPA Report No. EPA/600/R-12/003. January. https://nepis.epa.gov/Exe/ZyPDF.cgi/P100DGTB.PDF?Dockey=P100DGTB.PDF.
    \34\ Available at https://www.epa.gov/sites/default/files/2015-01/documents/assess2.pdf. Accessed January 9, 2024.
    \35\ SCS Engineers. 2009. Current MSW Industry Position and 
State-of-the-Practice on LFG Collection Efficiency, Methane 
Oxidation, and Carbon Sequestration in Landfills. Prepared for Solid 
Waste Industry for Climate Solutions (SWICS). Version 2.2. https://www.scsengineers.com/wp-content/uploads/2015/03/Sullivan_SWICS_White_Paper_Version_2.2_Final.pdf.
---------------------------------------------------------------------------

    Response: We reviewed the various studies cited by commenters, 
including available versions of the SWICS white paper. Upon review of 
these papers and comments received, we maintain our position that the 
historical collection efficiencies are overstated and that it is 
appropriate to apply the lower collection efficiency to all landfills. 
In our review of the SWICS white paper, which was the basis for the 
historical gas collection efficiencies, we noted that data were omitted 
due to poor operation of gas collection system. Thus, we consider the 
historical gas collection efficiencies to be representative of ideal 
gas collection efficiencies. In our proposal, we required facilities 
that conduct surface-emission monitoring data to apply a correction 
factor that would reduce the overall collection efficiency, clearly 
indicating that we thought the current collection efficiencies are 
overstated, even for regulated landfills. While we expected that the 
surface emission correction factor would result in lower emissions than 
those calculated using the 10-percentage point decrease in collection 
efficiency, based on our review of other studies correlating surface 
methane concentrations with methane flux, a more central tendency 
correlation factor is projected to yield emissions similar to a 10-
percentage point decrease in collection efficiency. All the measurement 
study data we reviewed suggests that current GHGRP collection 
efficiencies are overstated on average by 10-percentage points or more 
(Duan, et al., 2022 and Nesser, et al., 2023).\36\ In reviewing the 
data from Nesser, et al. (2023), including the supplemental 
information,\37\ we found that all 38 landfills for which gas 
collection systems were reported were subject to the NSPS or EG. 
Comparing the gas collection efficiencies directly reported in the 
GHGRP, 35 of the 38 landfills had lower or similar measured gas 
collection efficiencies to those reported in subpart HH. With a 10-
percentage point decrease in the default gas collection efficiencies, 
measured gas collection efficiencies were still at least 10-percentage 
points lower for 20 of the 38 landfills, approximately equivalent for 
13 landfills, and only higher than subpart HH proposed lower default 
collection efficiencies for 5 of the landfills. Similar low average 
collection efficiencies were noted by Duan, et al., (2022). Therefore, 
based on direct measurement data for landfills, we determined it is 
appropriate to finalize the lower default gas collection efficiencies 
and apply the lower gas collection efficiency for all landfills.
---------------------------------------------------------------------------

    \36\ Duan, Z., Kjeldsen, P., & Scheutz, C. (2022). Efficiency of 
gas collection systems at Danish landfills and implications for 
regulations. Waste management (New York, N.Y.), 139, 269-278. 
https://doi.org/10.1016/j.wasman.2021.12.023.
    \37\ See https://egusphere.copernicus.org/preprints/2023/egusphere-2023-946/egusphere-2023-946-supplement.pdf.
---------------------------------------------------------------------------

    While the Maryland study data suggests that the gas collection 
efficiency for voluntary systems may be lower than for regulated gas 
collection systems, we agree with commenters that these gas collection 
efficiencies are based on modeled generation rather than measured 
emissions. The DOC values for individual landfills can vary 
significantly and the differences observed could be due to differences 
in the wastes managed at the different Maryland landfills. We could not 
identify direct measurement study data by which to support further 
reductions in gas collection efficiencies for voluntary gas collection 
systems. Therefore, we are providing a single set of gas collection 
efficiencies for subpart HH reporters to use.
    In conclusion, we are finalizing gas collection efficiencies that 
are lower than those historically provided in subpart HH by 10-
percentage points based on comments received and review of recent 
landfill methane emission measurement studies for landfills with gas 
collection systems. We had proposed these collection efficiencies for 
facilities not conducting surface emission monitoring, but we are now 
finalizing these lower gas collection efficiencies for all landfills.
    Comment: Several commenters provided input on the proposed 
revisions to equations HH-6 through HH-8 to subpart HH to capture 
emissions from other large release events. Two commenters suggested 
that the EPA should require monitoring of both the pilot light and flow 
rate and that the ``fDest'' term should be excluded during 
any period the combustion device is not operating properly. The 
commenters specified that ``fDest'' should be excluded 
during any period when the reporter has operational data indicating 
that the combustion device is not operating according to manufacturer 
specifications or when the reporter has received credible monitoring 
data showing an unlit or malfunctioning control device.
    One commenter stated that the proposed revisions would be difficult 
to implement and tend to capture very limited or marginal data. The 
commenter asserted that gas collection systems by nature require 
constant adjustment of temperature, pressure, and other parameters or 
may be subject to frequent repairs that would not be expected to affect 
the overall control efficiency. The commenter asked the EPA to remove 
``normally'' from the first sentence of the proposed definition of 
``fRec'' and remove ``or poor operation, such as times when 
pressure, temperature, or other parameters indicative of operation are 
outside of normal variances,'' from the second sentence.
    The commenter also expressed concerns regarding how the proposed 
revisions to ``fDest'' applies to flares, stating that a 
large portion of landfill controls use open flares, or are equipped 
with automatic shutoffs, which have no parameters for monitoring 
effective operation other than the presence of a flame. The commenter 
requested the sentence addressing the pilot flame (``For flares, times 
when there is no pilot flame present must be excluded from the annual 
operating hours for the destruction device.'') be removed from the 
proposed revision of ``fDest,'' because it is confusing, 
unnecessary, and technically incorrect, as a pilot is typically only 
required during startup.
    One commenter also requested the EPA remove the phrase ``. . . as 
measured at the nth measurement location'' from the first sentence of 
``fDest'' description; the commenter stated the text adds 
confusion by implying that the time gas is sent to the nth measurement 
location is equal to the time gas is sent to the control device, which 
may be incorrect for measurement locations with more than one control 
device. The commenter also

[[Page 31857]]

proposed a definition striking out ``The annual operating hours for the 
destruction device should include only those periods when flow was sent 
to the destruction device and the destruction device was operating at 
its intended temperature or other parameter indicative of effective 
operation.'' The commenter added that because flares and other 
destruction devices are designed with fail-closed valves or other 
devices to prevent venting of gas when they are not operating, applying 
the definition as written overestimates emissions when a measurement 
location has more than one destruction device and all devices are not 
operating at the same time.
    Response: The EPA agrees with the commenters regarding monitoring 
the flow rate of the landfill gas; however, a change to the proposed 
rule is not necessary in this case as the continuous monitoring of the 
gas flow is already required in 40 CFR 98.343. The EPA disagrees with 
the comment that ``EPA should likewise specify that fDest 
must be excluded during any period when the pilot light and flow rate 
are not meeting manufacturer specifications for complete combustion.'' 
Adding this specification to the rule is not necessary as the revision 
to the definition of fDest already accounts for this 
scenario. The proposed revision to the fDest definition in 
the supplemental proposal states, ``The annual operating hours for the 
destruction device should include only those periods when flow was sent 
to the destruction device and the destruction device was operating at 
its intended temperature or other parameter indicative of effective 
operation.'' Thus, if the destruction device has manufacturer 
specifications for effective operation that are not met during its 
operation, the revision to the fDest definition requires 
those periods to be excluded in the hours for fDest. We will 
further evaluate how credible monitoring data may be defined and 
excluded from fDest in a future rulemaking.
    The EPA disagrees with the proposed edits to the definition of 
fRec, which are to remove the word ``normally'' from the 
first sentence and remove the phrase ``or poor operation, such as times 
when pressure, temperature, or other parameters indicative of operation 
are outside of normal variances'' from the second sentence. These edits 
would allow for all operating hours in the calculation regardless of 
how the system operated. We asked for comment on what set of parameters 
should be used to identify poorly operating periods and whether a 
threshold on the proportion of wells operating outside of their normal 
operating variance should be included in the definition of 
fRec to define periods of poor performance.
    With regards to the commenters' input on the definition of 
fDest, the EPA agrees with removing ``as measured at the nth 
measurement location'' from the first sentence of the definition as the 
commenter notes, ``flares and other destruction devices are designed 
with fail-closed valves or other devices to prevent venting of gas when 
they are not operating, keeping that phrase can overestimate emissions 
when a measurement location has more than one destruction device and 
all devices are not operating at the same time.'' We are revising this 
sentence to remove ``as measured at the nth measurement location.'' We 
disagree with removing from the definition ``For flares, times when 
there is no pilot flame present must be excluded from the annual 
operating hours for the destruction device.'' Instead, we are revising 
this sentence to read ``For flares, times when there is no flame 
present must be excluded from the annual operating hours for the 
destruction device.'' We believe the lack of a flame is an indication 
the flare is not operating effectively. Lastly, we disagree with 
removing the sentence, ``The annual operating hours for the destruction 
device should include only those periods when flow was sent to the 
destruction device and the destruction device was operating at its 
intended temperature or other parameter indicative of effective 
operation.'' We believe this sentence is necessary to ensure the 
calculation of fDest represents proper operation of the 
destruction device.
    Comment: We received several comments regarding the revised DOC 
values. Some commenters supported lowering of the default DOC for bulk 
waste from 0.20 to 0.17, citing similar findings in a 2019 
Environmental Research and Education Foundation (EREF) study.\38\ These 
commenters generally opposed the proposed default value of 0.27 for 
bulk MSW (excluding inerts and construction and demolition (C&D) waste) 
and the proposed default value of 0.32 for uncharacterized wastes and 
recommended the use of either the value of 0.19 from the EREF report or 
the 0.17 value for bulk wastes for these other general waste 
categories. According to these commenters, the EPA's method for 
determining the DOC for bulk MSW (excluding inerts and C&D waste) does 
not comport with how landfills characterize and manage input waste 
streams, and the high default DOC value for bulk MSW makes the modified 
bulk MSW option unusable. Other commenters opposed the proposed 
reduction in bulk waste and bulk MSW default DOC values, indicating 
that this will lead to lower emissions over the life of the landfill 
when research indicates emissions inventories of landfill emissions 
underestimate actual emissions. One commenter referenced a paper 
(Bahor, et al., 2010) that, according to the commenter, validated the 
default DOC of MSW to be 0.20.\39\ Other commenters noted that many 
landfill reporters were taking advantage of the composition method by 
only reporting inerts and uncharacterized wastes. These commenters 
supported the proposed default value of 0.32 for uncharacterized 
wastes.
---------------------------------------------------------------------------

    \38\ The Environmental Research & Education Foundation (2019). 
``Analysis of Waste Streams Entering MSW Landfills: Estimating DOC 
Values & the Impact of Non-MSW Materials.'' Available in the docket 
to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424.
    \39\ Bahor, Brian, et al. 2010. ``Life-cycle assessment of waste 
management greenhouse gas emissions using municipal waste combustor 
data.'' Journal of Environmental Engineering 136.8 (2010): 749-755. 
https://doi.org/10.1061/(ASCE)EE.1943-7870.0000189.
---------------------------------------------------------------------------

    Response: The EPA included a DOC of 0.20 for bulk waste in subpart 
HH because the data we reviewed circa 2000 to 2010 indicated that was 
the best fit DOC value.\40\ As noted in the memorandum ``Modified Bulk 
MSW Option Update'' included in Docket ID. No. EPA-HQ-OAR-2019-0424, we 
have seen a significant decrease in the percentage of paper and 
paperboard products being landfilled due to increased recycling of 
these waste streams. This change in the composition of MSW landfilled 
supports and confirms the drop in DOC from 0.20 to 0.17 over the time 
period between 2005 and 2011. With respect to the Bahor, et al. (2010) 
study, it appears that the HHV measurement data was made using data 
from 1996 to 2006, with biogenic correction factors developed over 2007 
and 2008. Based on the timing of the measurements made, agreement with 
the DOC value of 0.20 is not surprising and consistent with the 
findings by which we originally used a default DOC value of 0.20. We 
specifically sought to reassess the average DOC values considering more 
recent data to account for potential changes in DOC values over the 
past decade. Based on our analysis, an average DOC value of 0.17 
provides a better fit with current landfill practices. Therefore, we 
are finalizing a revision of the default DOC value to

[[Page 31858]]

0.17 as proposed. However, we note that the proposed revision was not 
clear regarding how the new DOC value should be incorporated into the 
facility's emissions estimate. Some reporters may only begin applying 
the new DOC value to new wastes being disposed of in 2025 and later 
years. Other reporters may opt to revise the DOC value for all wastes 
disposed of in the landfill for all previous disposal years. This could 
lead to significant discrepancies between emissions reported by 
reporters with similar landfills and also between the emissions 
reported for different years by a given reporter. As noted in this 
discussion, we expect that wastes disposed of prior to 2010 are best 
characterized using a default DOC value of 0.20 and that wastes 
disposed of in 2010 and later years are best characterized using a 
default DOC of 0.17. Therefore, while we are finalizing a revision in 
the default bulk waste DOC value to 0.17, we are also finalizing 
clarifications to these revisions to incorporate these revisions 
consistently across reporters and consistent with the timeframe where 
the reduction in DOC occurred. Specifically, we are maintaining the 
historic DOC value of 0.20 for historic disposal years (prior to 2010) 
and, starting with RY2025, requiring the use of the revised DOC value 
of 0.17 for disposal years 2010 and later (see memorandum ``Revised 
Analysis and Calculation of Optimal k values for Subpart HH MSW 
Landfills Using a 0.17 DOC Default and Timing Considerations'' 
available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424).
---------------------------------------------------------------------------

    \40\ RTI International (2004). Solid Waste Inventory Support--
Review Draft: Documentation of Methane Emission Estimates. Prepared 
for U.S. EPA, Office of Atmospheric Programs, Washington, DC. 
September 29.
---------------------------------------------------------------------------

    With respect to the proposed DOC value for bulk MSW (excluding 
inerts and C&D waste), the approach we used to develop the proposed DOC 
value is consistent with the approach we used when we originally 
developed and provided the modified bulk waste option following 
consideration of comments received (75 FR 66450, October 28, 2010). 
This option was specifically provided to address comments that the 
waste composition option was too detailed for most landfill operators 
to use and that landfill operators should have the opportunity to 
characterize some of the waste received as inerts under the bulk waste 
option. Because the DOC values for bulk waste option were derived based 
on the full quantity of waste disposed at landfills, that DOC value for 
bulk waste intrinsically includes inerts. Therefore, we sought to 
develop a representative MSW DOC value that excludes inerts for use in 
the modified bulk MSW option. We disagree that this makes the modified 
bulk waste option inaccurate or unusable. On the contrary, we find that 
using the bulk waste DOC value in the modified bulk MSW option would be 
less accurate for predicting the CH4 generation for the 
modified bulk MSW option because the DOC value for bulk waste was 
determined by the full quantity of waste disposed at landfills 
including inerts and C&D waste. We also agree with commenters that some 
reporters are misusing the waste composition option in order to 
separately account for inerts but then use the bulk waste DOC value for 
the rest of the MSW. We conducted a multivariant analysis to project 
the DOC of uncharacterized MSW in landfills for which reporters used 
the waste composition method and the DOC for this uncharacterized waste 
was estimated to be 0.32. This agrees well with the proposed DOC value 
for bulk MSW of 0.27 and confirms that, when facilities separately 
report inert waste quantities, the DOC for the remaining MSW (excluding 
inerts and C&D waste) is much higher than suggested by some of the 
commenters. Consequently, we concluded that our proposed values of 0.27 
for bulk MSW (excluding inerts and C&D waste) and 0.32 for 
uncharacterized waste should be finalized as proposed. Similar to our 
clarification regarding how the revision in bulk waste DOC must be 
implemented, we are finalizing requirements to use the current bulk MSW 
(excluding inerts and C&D waste) DOC value of 0.31 for historic 
disposal years (prior to 2010) and requiring the use of the revised 
bulk MSW (excluding inerts and C&D waste) DOC value of 0.27 for 
disposal years 2010 and later, consistent with the timeline for which 
these values were determined. Because we have no method to indicate a 
change in DOC for uncharacterized wastes, we are requiring the use of 
the new DOC for uncharacterized waste using the composition option of 
0.32 for all years for which the composition option was used.
    We also disagree with commenters that having a high bulk MSW 
default DOC value makes the modified bulk MSW method unusable. Based on 
waste characterization data as reported for RY2022, approximately 23 
percent use the modified bulk MSW method, which suggests a quarter of 
the reports find the modified bulk MSW option useful. While this option 
was specifically provided for landfills that accept large quantities of 
C&D waste or inert waste streams, we disagree that its use should be 
restricted to that scenario. There is significant variability in the 
DOC of bulk waste from landfill to landfill. There are many cases when 
the quantity of landfill gas recovered exceeds the modeled methane 
generation rates. This is a clear indication that the default DOC (and/
or k value) is too low. For reporters with high actual CH4 
generation rates, as noted by the quantity of CH4 recovered 
at the landfill, we find that the use of the modified bulk MSW option 
is appropriate for these reporters and would likely provide a more 
accurate estimate of modeled CH4 generation, even if these 
reporters do not have large quantities of inert or C&D wastes. We 
encourage reporters that have CH4 recovery rates exceeding 
their modeled CH4 generation rates to evaluate and use, as 
appropriate, the modified bulk MSW or waste composition options in 
order to more accurately estimate modeled methane generation.
    Comment: Several comments supported revisions to decay rate 
constants (k values) that more closely match the IPCC recommendations. 
Other comments were critical of the revisions, suggesting the proposed 
k values were too high. One commenter noted that the original k values 
were developed using a separate analysis considering the use of the 
CH4 generation potential (Lo, analogous to the DOC input for 
the first order decay model used in subpart HH). The commenter noted 
that optimizing k and DOC values simultaneously can lead to extreme and 
unrealistic values because an error in one value causes an offsetting 
error in the other. The commenter also stated that the EPA allowed an 
extremely wide range for the ``optimized'' k values (e.g., 0.001 to 
0.400 for dry climates) and should have constrained the k values to 
more realistic values. The commenter also suggested that the EPA rely 
on its own research as published in PLoS ONE (Jain et al., 2021).\41\ 
Finally, the commenter suggested that multivariant analysis was not 
peer-reviewed and therefore does not appear to comply with the General 
Assessment Factors.
---------------------------------------------------------------------------

    \41\ Jain, P., et al. 2021. ``Greenhouse gas reporting data 
improves understanding of regional climate impact on landfill 
methane production and collection.'' PLoS ONE, at 1-3, 10-11 (Feb. 
26, 2021), available at https://journals.plos.org/plosone/article?id=10.1371/journal.pone.0246334.
---------------------------------------------------------------------------

    Response: The EPA reviewed the documentation supporting the 
existing DOC and k value defaults used for subpart HH (RTI 
International, 2004). Importantly, the memorandum documents that the 
development of the DOC and k values utilized a two-step process. The 
first step was a

[[Page 31859]]

multivariant analysis, similar to the analysis conducted in 2019 
(McGrath et al., 2019), which was used to determine an optimal DOC 
value. The second step was to determine optimal k values for each 
precipitation range using the optimal DOC value from the multivariant 
analysis. At proposal, we used the DOC and k values determined directly 
from the multivariant analysis. After consideration of the comments 
received and the approach used historically, we determined that it 
would be more appropriate to determine optimal k values once the 
default DOC value is established. We agree with the commenter that 
using a fixed DOC value (set at the proposed bulk waste DOC value of 
0.17), we expect that the optimal k values in a single-variable 
analysis would have less variability and better predict methane 
generation across landfills when using the revised DOC default. 
Therefore, we conducted this second step of the analysis using the 
original data set for facilities using the bulk waste approach to 
determine the optimal k values for these landfills, given a default DOC 
value of 0.17 (the bulk waste DOC value recommended in the McGrath et 
al. (2019) memo based on the multivariant analysis).
    We also reviewed additional literature to assess reasonable ranges 
for k values. We found that the lowest allowed k value of 0.001 
yr^-1 was unrealistic and much lower than any k value 
reported in the literature. We identified some studies suggesting a k 
value of 0.4 yr^-1 is possible for wet landfills (or 
landfills using leachate recirculation). After our review of the 
additional literature, we revised the allowable k value range from 
0.001-0.4 yr^-1 to 0.007-0.3 yr^-1. The results of 
applying this second step of the analysis, consistent with the approach 
used previously to develop default k values, indicate that the optimal 
k values for dry, moderate, and wet climates were 0.033, 0.067, and 
0.098 yr^-1, respectively (see memorandum ``Revised Analysis 
and Calculation of Optimal k Values for Subpart HH MSW Landfills Using 
a 0.17 DOC Default and Timing Considerations'' available in the docket 
to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424). These values 
are lower than those developed from the multivariant analysis, but 
still significantly higher than the current defaults in subpart HH. 
These values also align well with IPCC recommended k value ranges for 
moderately decaying waste and the k values reported by Jain, et al. 
(2021). Table 5 of this preamble presents a comparison of the old 
subpart HH and revised k values with the values recommended by the IPCC 
and Jain, et al. (2021).

       Table 5--Comparison of Finalized Decay Rate Constants (k Values in yrs-\1\) by Precipitation Range
----------------------------------------------------------------------------------------------------------------
                                            Historic                      IPCC default
                                         subpart HH and      Revised       decay value     Jain, et al. (2021),
           Precipitation zone               inventory      subpart HH    (k) ranges for    recommended k value
                                          default decay   default decay    moderately      (and 95% confidence
                                            value (k)       value (k)    decaying waste           range)
----------------------------------------------------------------------------------------------------------------
Dry (<20 inches/year)..................            0.02           0.033       0.04-0.05      0.043 (0.033-0.054)
Moderate (20-40 inches/year)...........           0.038           0.067        0.04-0.1      0.074 (0.061-0.088)
Wet (>40 inches/year)..................           0.057           0.098       0.07-0.17      0.090 (0.077-0.105)
----------------------------------------------------------------------------------------------------------------

    Similar to the incorporation of the new DOC values, we note that 
the proposed revision was not clear regarding how the new k values for 
bulk waste under the ``Bulk waste option'' and bulk MSW under the 
``Modified bulk MSW option'' should be incorporated into the facility's 
emissions estimate. While we are finalizing revisions for the default 
bulk waste k values for dry, moderate, and wet climates as 0.033, 
0.067, and 0.098 yr^-1, respectively, we are also finalizing 
clarifications to these revisions to incorporate these revisions 
consistently across reporters and consistent with the timeframe where 
the reduction in DOC occurred. Specifically, starting in RY2025, we are 
maintaining the historic k values of 0.20, 0.038, and 0.057 
yr^-1 for historic disposal years (prior to 2010) and 
requiring the use of the revised k values of 0.033, 0.067, and 0.098 
yr^-1 for disposal years 2010 and later. We are finalizing 
requirements under the modified bulk waste MSW option to use the 
current bulk MSW (excluding inerts and C&D waste) k values of 0.02 to 
0.057 yr^-1 for historic disposal years (prior to 2010) and 
requiring the use of the revised bulk MSW (excluding inerts and C&D 
waste) k values of 0.033 to 0.098 yr^-1 for disposal years 
2010 and later, consistent with the timeline for which these values 
were determined. Because we have no method to indicate a change in k 
value for uncharacterized wastes, we are requiring the use of the new k 
values for uncharacterized waste using the composition option of 0.033 
to 0.098 for all years for which the composition option was used.
    With respect to compliance with the General Assessment Factors, we 
considered a wide variety of information, including peer-reviewed 
material, when developing our proposed and final k values. While our 
technical support documents are not formally peer reviewed at proposal, 
we consider the proposal/public review process to be an adequate forum 
for public review of our analysis and conclusions. After considering 
the public comments received, we revised our analysis to more closely 
match the original approach used to determine default k values. We also 
adjusted our allowable range for k values based on public comment and 
additional literature review. All information we have reviewed indicate 
that the historic subpart HH k values are too low and that the values 
we determined in our re-analysis of the data will provide improved 
methane generation estimates. For these reasons, we are finalizing 
revised k values for subpart HH of 0.033, 0.067, and 0.098 
yr^-1 for dry, moderate, and wet climates, respectively. 
These k values apply to bulk waste, bulk MSW, and uncharacterized MSW, 
as proposed.

U. Subpart OO--Suppliers of Industrial Greenhouse Gases

    We are finalizing several amendments to subpart OO of part 98 
(Suppliers of Industrial Greenhouse Gases) as proposed. Section 
III.U.1. of this preamble discusses the final revisions to subpart OO. 
The EPA received comments on the proposed revisions to subpart OO which 
are discussed in section III.U.2. of this preamble. We are also 
finalizing as proposed confidentiality determinations for new data 
elements resulting from the revisions to subpart OO as described in 
section VI. of this preamble.

[[Page 31860]]

1. Summary of Final Amendments to Subpart OO
    This section summarizes the final amendments to subpart OO. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart OO can be found in this section and 
section III.U.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal.
    The EPA is finalizing several revisions to subpart OO of part 98 
that will improve the quality of the data collection under the GHGRP. 
First, we are adding a requirement at 40 CFR 98.417(c)(7) for bulk 
importers of F-GHGs to include, as part of the information required for 
each import in the annual report, the customs entry number. The customs 
entry number is provided as part of the U.S. Customs and Border 
Protection (CBP) Form 7501: Entry Summary and is assigned for each 
filed CBP entry for each shipment. The EPA has made one minor 
clarification from proposal. We initially proposed the requirement as 
the ``customs entry summary number''; the final rule modifies 40 CFR 
98.416(a)(7) to clarify the requirement to the ``customs entry 
number,'' which is associated with the CBP Form 7501, ``Entry 
Summary.''
    As proposed, we are adding a reporting requirement at 40 CFR 
98.416(k) that suppliers of N2O, saturated PFCs, 
SF6, and fluorinated HTFs identify the end uses for which 
the N2O, SF6, saturated PFC, or fluorinated HTF 
is used and the aggregated annual quantities of N2O, 
SF6, each saturated PFC, or each fluorinated HTF transferred 
to each end use, if known. As discussed in the proposed rules, this 
requirement is based on a similar requirement in subpart PP to part 98 
(Suppliers of Carbon Dioxide) and is intended to provide additional 
insight into the identities and magnitudes of the uses of these 
compounds, which are currently less well understood than those of other 
industrial GHGs such as HFCs, although the GWP-weighted totals supplied 
are relatively large.
    The EPA is also finalizing a clarification to the reporting 
requirements for importers and exporters of F-GHGs, F-HTFs, or 
N2O, to revise the required reporting of ``commodity code,'' 
which is required for importers at 40 CFR 98.416(c)(6) and for 
exporters at 40 CFR 98.416(d)(4), to clarify that reporters should 
submit the Harmonized Tariff System (HTS) code for each F-GHG, F-HTF, 
or N2O shipped. Reporters will enter the full 10-digit HTS 
code with decimals, to extend to the statistical suffix, as it was 
entered on related customs forms. See section III.S. of the preamble to 
the 2022 Data Quality Improvements Proposal for additional information 
on the EPA's rationale for these changes.
    As discussed in section III.A.1.b. of this preamble, we are 
finalizing related revisions to the definition of ``fluorinated HTF,'' 
previously included in subpart I of part 98 (Electronics 
Manufacturing), and to move the definition to subpart A of part 98 
(General Provisions), to harmonize with the changes to subpart OO.
    Finally, we are finalizing revisions to 40 CFR 98.416(c) and (d) to 
clarify that certain exceptions to the reporting requirements for 
importers and exporters are voluntary, consistent with our original 
intent. To implement this change, we are finalizing revisions to insert 
``importers may exclude'' between ``except'' and ``for shipments'' in 
the first sentence of Sec.  98.416(c) and (d), deleting the ``for.'' We 
are also finalizing revisions to clarify that imports and exports of 
transshipments will both have to be either included or excluded for any 
given importer or exporter, and we are finalizing a similar 
clarification for heels. These changes ensure that importers and 
exporters treat the exceptions consistently. See section III.K. of the 
preamble to the 2023 Supplemental Proposal for additional information 
on these revisions and their supporting basis.
    In the 2023 Supplemental Proposal, the EPA proposed a requirement 
at 40 CFR 98.416(c) for bulk importers of F-GHGs to provide, for GHGs 
that are not regulated substances under 40 CFR part 84 (Phasedown of 
Hydrofluorocarbons), copies of the corresponding U.S. CBP entry forms 
(e.g., CBP Form 7501) in their annual report. Following consideration 
of public comments received on a similar proposed revision to subpart 
QQ of part 98 (Importers and Exporters of Fluorinated Greenhouse Gases 
Contained in Pre-Charged Equipment and Closed-Cell Foams), including 
concerns regarding the availability of this information and the 
potential burden of submitting large volumes of entry forms, the EPA is 
not taking final action on the proposed revision to subpart OO. See 
section III.W. of this preamble for additional information.
2. Summary of Comments and Responses on Subpart OO
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart OO. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart OO.
    Comment: One commenter requested that we clarify that chemical 
supply ``end use'' refers to industry category only, such as 
electronics or semiconductor use, and does not refer to more specific 
uses. The commenter recommended that specific purchases and purposes of 
chemical use should be considered industry confidential business 
information and therefore protected from public disclosure. The 
commenter also noted that chemical suppliers or distributors do not 
typically have visibility to end use, particularly specific end use 
categories.
    Response: As discussed in section VI. of this preamble, we are 
planning to finalize our proposed determination that the two new 
subpart OO data elements (the end use(s) to which the N2O, 
SF6, each PFC, or each fluorinated HTF is transferred and 
the aggregated annual quantity of the GHG that is transferred to that 
end use application) are ``Eligible for Confidential Treatment.'' This 
will protect the data from public disclosure. Regarding suppliers' 
knowledge of the uses of compounds within each industry, suppliers are 
required to report the end uses only ``if known.'' For N2O, 
SF6, and saturated PFCs, the end uses that we identified in 
the proposed rule coincided with individual industries and not specific 
uses within those industries. For fluorinated HTFs, the end uses that 
we identified in the proposed rule coincided with some specific uses 
within industries, such as cleaning versus temperature control within 
the electronics industry. This was because different end uses, even 
within the same industry, have different emission patterns, which 
affect the relationship between emissions and consumption of these 
compounds. (For example, end uses that quickly emit the F-HTF, such as 
cleaning, are expected to have emissions that are close to consumption, 
whereas end uses that store the F-HTF, such as process cooling, may 
have emissions that are less than half of consumption.) However, the 
electronics industry, unlike other industries that

[[Page 31861]]

use F-HTFs, reports its F-HTF emissions to EPA. Thus, in the subpart OO 
electronic reporting form, we are planning to list ``electronics 
manufacturing'' (including manufacturing of semiconductors, MEMS, 
photovoltaic cells, and displays), and not specific uses within 
electronics manufacturing, among the end uses whose consumption of the 
fluorinated HTF will be reported.

V. Subpart PP--Suppliers of Carbon Dioxide

    We are finalizing several amendments to subpart PP of part 98 
(Suppliers of Carbon Dioxide) as proposed. This section discusses the 
final revisions to subpart PP. The EPA received comments on the 
proposed revisions to subpart PP. See the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart PP.
    The EPA is finalizing several revisions to subpart PP to improve 
the quality of the data collected from this subpart. As proposed, we 
are adding new 40 CFR 98.420(a)(4) and a new definition to 40 CFR 98.6 
to explicitly include direct air capture (DAC) as a capture option 
under subpart PP. Unlike conventional capture sources where 
CO2 is separated during the manufacturing or treatment phase 
of product stream, DAC captures CO2 from ambient air using 
aqueous or solid sorbents, which is then processed into a concentrated 
stream for utilization or injection underground. This final rule 
provides that DAC, ``with respect to a facility, technology, or system, 
means that the facility, technology, or system uses carbon capture 
equipment to capture carbon dioxide directly from the air. DAC does not 
include any facility, technology, or system that captures carbon 
dioxide (1) that is deliberately released from a naturally occurring 
subsurface spring or (2) using natural photosynthesis.''
    The EPA is also finalizing an amendment to the definition of 
``carbon dioxide stream'' in 40 CFR 98.6 to add ``captured from ambient 
air (e.g., direct air capture)'' to the definition so that it reads, 
``Carbon dioxide stream means carbon dioxide that has been captured 
from an emission source (e.g., a power plant or other industrial 
facility), captured from ambient air (e.g., direct air capture), or 
extracted from a carbon dioxide production well plus incidental 
associated substances either derived from the source materials and the 
capture process or extracted with the carbon dioxide.''
    We are finalizing harmonizing changes to 40 CFR 98.422, 98.423, 
98.426, and 98.427 to add references to DAC into the reporting 
requirements. The final rule also amends 40 CFR 98.426 as proposed to 
add additional reporting requirements in paragraph (i) to require DAC 
facilities to report the annual quantities and sources (e.g., non-
hydropower renewable sources, natural gas, oil, coal) of on-site and 
off-site sourced electricity, heat, and combined heat and power used to 
power the DAC plant. These quantities must represent the electricity 
and heat used starting from the air intake at the facility and ending 
with the compressed CO2 stream (i.e., the CO2 
stream ready for supply for commercial applications or, if maintaining 
custody of the stream, sequestration or injection of the stream 
underground). These quantities must be provided per energy source, if 
known. For electricity provided to the DAC plant from the grid, 
reporters must additionally provide identifying information for the 
facility and electric utility company. In addition, for on-site sourced 
electricity, heat, and combined heat and power, DAC facilities must 
indicate whether flue gas is also captured by the DAC process unit. 
These changes will aid the EPA in understanding this emerging 
technology at facilities that utilize DAC and in better understanding 
potential net emissions impacts associated with DAC facilities 
(particularly given that interest in DAC is primarily intended to be a 
carbon removal technology to achieve climate benefits). See section 
III.T. of the preamble to the 2022 Data Quality Improvements Proposal 
for additional information on the EPA's rationale for these changes.
    The EPA is finalizing two additional revisions to improve data 
quality. First, we are finalizing the addition of a data element to 40 
CFR 98.426(f) that will require suppliers to report the annual quantity 
of CO2 in metric tons that is transferred for use in 
geologic sequestration with EOR subject to new subpart VV to part 98 
(Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery 
Using ISO 27916). To inform the revision of the subpart PP electronic 
reporting form, the EPA also sought comment on potential end use 
applications to add to 40 CFR 98.426(f), such as algal systems, 
chemical production, and mineralization processes, such as the 
production of cements, aggregates, or bicarbonates. However, because 40 
CFR 98.426(f) already includes a reporting category for ``other,'' the 
existing rule already provides flexibility for this reporting, and we 
are not taking final action on the addition of specific end-use 
applications to 40 CFR 98.426 at this time. The EPA may consider the 
addition of other end-use applications in a future rulemaking.
    Second, the EPA is finalizing as proposed that 40 CFR 98.426(h) 
will apply to any facilities that capture a CO2 stream from 
a facility subject to 40 CFR part 98 and supply that CO2 
stream to facilities that are subject to either subpart RR (Geologic 
Sequestration of Carbon Dioxide) or new subpart VV. The revised 
paragraph will no longer apply only to suppliers that capture 
CO2 from EGUs subject to subpart D (Electricity Generation), 
but also to suppliers that capture CO2 from any direct 
emitting facility that is subject to 40 CFR part 98 and transfer to 
facilities subject to subparts RR or VV. Reporters must provide the 
facility identification number associated with the facility that is the 
source of the captured CO2 stream, each facility 
identification number associated with the annual GHG reports for each 
subpart RR and subpart VV facility to which CO2 is 
transferred, and the annual quantity of CO2 transferred to 
each subpart RR and VV facility. See section III.L. of the preamble to 
the 2023 Supplemental Proposal for additional information.
    The EPA also requested comment on, but did not propose, expanding 
the requirement at 40 CFR 98.426(h) such that facilities subject to 
subpart PP would report transfers of CO2 to any facilities 
reporting under 40 CFR part 98, not just those subject to subparts RR 
and VV. This would include reporting the amount of CO2 
transferred on an annual basis as well as the relevant GHGRP facility 
identification numbers. The EPA further requested comment on whether 
information regarding additional end uses would be available to 
facilities. Following consideration of public comments, we are not 
extending the reporting requirements at this time but may consider 
doing so in a future rulemaking.
    We are finalizing, with revisions, related confidentiality 
determinations for data elements resulting from the revisions to 
subpart PP as described in section VI. of this preamble.

W. Subpart QQ--Importers and Exporters of Fluorinated Greenhouse Gases 
Contained in Pre-Charged Equipment and Closed-Cell Foams

    We are finalizing the amendments to subpart QQ of part 98 
(Importers and Exporters of Fluorinated Greenhouse Gases Contained in 
Pre-Charged

[[Page 31862]]

Equipment and Closed-Cell Foams) as proposed. In some cases, we are 
finalizing the proposed amendments with revisions. Section III.W.1. 
discusses the final revisions to subpart QQ. The EPA received several 
comments on proposed subpart QQ revisions which are discussed in 
section III.W.2. We are also finalizing as proposed confidentiality 
determinations for new data elements resulting from the final revisions 
to subpart QQ, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart QQ
    This section summarizes the final amendments to subpart QQ. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart QQ can be found in this section and 
section III.W.2. of this preamble. Additional rationale for these 
amendments are available in the preamble to the 2023 Supplemental 
Proposal.
    We are finalizing two revisions from the 2023 Supplemental 
Proposal. We are finalizing requirements for importers and exporters of 
fluorinated GHGs contained in pre-charged equipment or closed-cell 
foams to include, for each import and export, the HTS code (for 
importers, at 40 CFR 98.436(a)(7)) and the Schedule B code (for 
exporters, at 40 CFR 98.436(b)(7)) used for shipping each equipment 
type. These requirements are consistent with the final revisions to 
subpart OO of part 98 (Suppliers of Industrial Greenhouse Gases), which 
clarify that reporters should submit the HTS code for each shipment, as 
discussed in section III.U. of this preamble. See section III.S. of the 
preamble to the 2023 Supplemental Proposal for additional information 
on the EPA's rationale for these changes.
    The EPA also proposed to revise 40 CFR 98.436 to add a requirement 
to include collecting copies of the U.S. CBP entry form (e.g., CBP form 
7501) for each reported import, which are currently maintained as 
records under 40 CFR 98.437(a). Following consideration of public 
comments, the EPA is not taking final action on the proposed 
requirement to submit copies of each U.S. CBP entry form. See section 
III.W.2. of this preamble for a summary of the related comments and the 
EPA's response.
2. Summary of Comments and Responses on Subpart QQ
    This section summarizes the major comments and responses related to 
the proposed amendments and supplemental amendments to subpart QQ. See 
the document ``Summary of Public Comments and Responses for 2024 Final 
Revisions and Confidentiality Determinations for Data Elements under 
the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-
0424 for a complete listing of all comments and responses related to 
subpart QQ.
    Comment: Several commenters contested the EPA's proposed 
requirements to collect a copy of the corresponding U.S. CBP entry form 
(e.g., Form 7501) for each reported import in 40 CFR 98.436. Some 
commenters asserted that the information available in the forms is 
currently provided electronically to CBP through the Automated 
Commercial Environment (ACE) and should be available to the EPA within 
the need for reporters to develop or submit copies. The commenters 
noted that this information should be sufficient to identify which 
entries are subject to data requirements under subpart QQ. Commenters 
recommended that the EPA should coordinate with CBP through established 
bodies (e.g., the Border Interagency Executive Council and Commercial 
Targeting and Analysis Center, to which the EPA already participates) 
to identify and utilize this data. One commenter specifically 
recommended that the EPA review the Entry Summary Line Detail Report, 
which would show the total quantity reported for entry summary lines by 
tariff number for the reported unit of measure. The commenters stated 
that such reports capture the actual data in CBP's system, as filed by 
importers, and should be sufficient to ensure that the Agency is able 
to improve the verification and accuracy of the data it collects. One 
commenter expressed that if the EPA is unable to identify applicable 
entries through more efficient means, importers should only be asked to 
identify specific entry numbers that will allow the EPA to identify the 
applicable electronic submissions within ACE.
    Commenters objected to the implied submission of hard-copy entry 
records as an unnecessary administrative burden. Commenters stated that 
the proposed requirement runs counter to CBP's longstanding effort to 
collect import data and documents electronically. One commenter stated 
that submittal of the border crossing document would necessitate a 
substantial amount of additional work and resources to comply, 
including gathering documentation from multiple sources prior to annual 
reporting. Another commenter noted that in some cases, importers could 
be required to file over 70,000 entries or forms. One commenter stated 
that this would require at least 1,300 manual searches for the 
appropriate forms for each entry. Commenters urged that this would be 
prohibitively expensive and burdensome. One commenter pointed out that 
this would require substantial modifications to automakers' existing 
information systems and processes for their GHG and related reporting 
obligations. Other commenters noted that paper form requirements would 
obfuscate industry efforts to further automate their record-keeping and 
reporting systems. One commenter added that the increased volume of 
documentation would likely put much more pressure on businesses than 
they can manage based on the current requirement to file data by March 
31st of the year following the reporting year.
    One commenter stated that the CBP forms would merely confirm the 
amount of foam board imported or exported and would not validate the F-
GHG quantity which is the intent of the report. The commenter continued 
that, even if border documents were provided, it would be impossible 
for the EPA to validate the current reports as the calculations 
involved to provide the volume of F-gas per board foot would require 
detailed technical knowledge, including density of the foam board.
    Some commenters asserted that the entry form requirement runs 
counter to Executive Order 13659 and 19 U.S.C. 1411(d), as amended by 
sections 106 and 107 of the Trade Facilitation and Trade Enforcement 
Act of 2015, which advance the goal of providing for electronic 
transmission of import data and seek to eliminate the need for 
duplicative information submissions across U.S. government agencies 
with regulatory authority related to goods entered or imported into the 
United States.
    Other commenters questioned the EPA's requirements to require 
reporting of the HTS) code for each type of pre-charged equipment or 
closed-cell foam imported and/or the Schedule B code for each type of 
pre-charged equipment or closed-cell foam exported. One commenter 
questioned whether the inclusion of both HTS codes and Schedule B codes 
is necessary for validation of the data that is currently collected, as 
all polystyrene foams use the same codes. The commenter urged that 
requiring more than one type of document would prove redundant in 
showing product type; be burdensome for manufacturers and for the EPA; 
and would not provide any additional

[[Page 31863]]

clarity or validation to the current report.
    Another commenter stated that only the border crossing document 
(which includes the customs tariff number, with the first six digits of 
an HTS and Schedule B number) should be required as part of the annual 
report. The commenter noted that these border crossing documents share 
highly sensitive information such as quantity and price, so should be 
handled securely. One commenter reiterated that all data proposed to be 
collected is, and would be, considered highly confidential business 
information. The commenter added that access to this type of 
information is restricted internally, which adds complexity to who 
could manage and deal with the processing of this documentation within 
facilities.
    Response: The EPA is revising the final rule to remove the 
requirement for reporters to submit copies of their U.S. CBP form 7501. 
Following consideration of comments received, it has been determined 
that annually reporting these documents could pose a significant burden 
for many reporters. Therefore, the EPA is not adopting the proposed 
data reporting requirement in the final rule.
    The EPA is finalizing the proposed requirement to report HTS codes 
(for imports) and Schedule B codes (for exports) to assist the Agency 
in verification of data. This requirement will allow the EPA to better 
compare reported GHGRP data with data from other government sources, 
specifically CBP records. As only one type of code (HTS or Schedule B) 
will be required based on whether the shipment is an import or export, 
this will not require the reporting of redundant information to the 
EPA. Furthermore, we are making ``No Determination'' of confidentiality 
for this data element. ``No Determination'' means that the EPA is not 
making a confidentiality determination through rulemaking at this time. 
If necessary, the EPA will evaluate and determine the confidentiality 
status of this data on a per-facility basis in accordance with the 
provisions of 40 CFR part 2, subpart B.

X. Subpart RR--Geologic Sequestration of Carbon Dioxide

    We are finalizing amendments to subpart RR of part 98 (Geologic 
Sequestration of Carbon Dioxide) as proposed. This section discusses 
the substantive final revisions to subpart RR. The EPA received only 
one supportive comment for subpart RR. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart RR. 
Additional rationale for these amendments is available in the preamble 
to the 2023 Supplemental Proposal.
    We are adding a definition for ``offshore'' to 40 CFR 98.449 to 
mean ``seaward of the terrestrial borders of the United States, 
including waters subject to the ebb and flow of the tide, as well as 
adjacent bays, lakes or other normally standing waters, and extending 
to the outer boundaries of the jurisdiction and control of the United 
States under the Outer Continental Shelf Lands Act.'' This definition 
clarifies the applicability of subpart RR to offshore geologic 
sequestration activities, including on the outer continental shelf. 
Additional rationale for these amendments is available in the preamble 
to the 2023 Supplemental Proposal.

Y. Subpart SS--Electrical Equipment Manufacture or Refurbishment

    We are finalizing several amendments to subpart SS of part 98 
(Electrical Equipment Manufacture or Refurbishment) as proposed. In 
some cases, we are finalizing the proposed amendments with revisions. 
Section III.Y.1. of this preamble discusses the substantive final 
revisions to subpart SS. The EPA received several comments on the 
proposed revisions to subpart SS which are addressed in section 
III.Q.2. of this preamble. We are also finalizing as proposed 
confidentiality determinations for new data elements resulting from the 
revisions to subpart SS as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart SS
    This section summarizes the final amendments to subpart SS. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other final 
revisions to 40 CFR part 98, subpart SS can be found in this section 
and section III.Y.2. of this preamble. Additional rationale for these 
amendments is available in the preamble to the 2022 Data Quality 
Improvements Proposal.

a. Revisions To Improve the Quality of Data Collected for Subpart SS

    The EPA is finalizing several revisions to subpart SS to improve 
the quality of the data collected from this subpart. We are generally 
finalizing as proposed revisions to the calculation, monitoring, and 
reporting requirements of subpart SS (at 40 CFR 98.452, 98.453, 98.454, 
and 98.456) to require reporting of additional F-GHGs as defined under 
40 CFR 98.6, except electrical equipment manufacturers and refurbishers 
will not be required to report emissions of insulating gases with 
weighted average GWPs of one (1) or less. However, they will be 
required to report the quantities of insulating gases with weighted 
average GWPs of one or less, as well as the nameplate capacities of the 
associated equipment, that they transfer to their customers. To 
implement these revisions, we are finalizing revisions that redefine 
the source category at 40 CFR 98.450 to include equipment containing 
``fluorinated GHGs (F-GHG), including but not limited to sulfur-
hexafluoride (SF6) and perfluorocarbons (PFCs).'' The 
changes also apply to the threshold in 40 CFR 98.451, which we are 
revising as discussed in section III.Y.1. of this preamble. Facilities 
also must consider additional F-GHGs purchased by the facility in 
estimating emissions for comparison to the threshold.
    The revisions to subpart SS include the addition of a new equation 
SS-1 in the reporting threshold at 40 CFR 98.451 (discussed in section 
III.Y.b. of this preamble) and a new equation SS-2 in the GHGs to 
report at 40 CFR 98.452. Equation SS-2 is also used in the definition 
of ``reportable insulating gas,'' discussed in this section of the 
preamble. We are also making minor revisions to equations SS-1 through 
SS-6 (which we are renumbering as SS-3 through SS-8 to accommodate new 
equations SS-1 and SS-2) to incorporate the estimation of emissions 
from all F-GHGs within the existing calculation methodology. To account 
for the possibility that the same fluorinated GHG could be a component 
of multiple reportable insulating gases, we are inserting in the final 
rule a summation sign at the beginning of the right side of equation 
SS-3 to ensure that emissions of each fluorinated GHG i are summed 
across all reportable insulating gases j. In addition, we are updating 
the monitoring and quality assurance requirements to account for 
emissions from additional F-GHGs, and harmonizing revisions to the 
reporting requirements such that reporters account for the mass of each 
F-GHG at the facility level.
    We are also finalizing the proposed definition of ``insulating 
gas'' and adding the term ``reportable insulating gas,'' which is 
defined as ``an insulating gas whose weighted average GWP, as 
calculated in equation SS-2, is greater

[[Page 31864]]

than one. A fluorinated GHG that makes up either part or all of a 
reportable insulating gas is considered to be a component of the 
reportable insulating gas.'' This term is intended to distinguish 
between insulating gases whose emissions must be reported under subpart 
SS and insulating gases whose emissions are not required to be reported 
under subpart SS (although, as noted above, the quantities of all 
insulating gases supplied to customers must be reported). In many 
though not all cases, we are also replacing occurrences of the proposed 
phrase ``fluorinated GHGs, including PFCs and SF6'' with 
``fluorinated GHGs that are components of reportable insulating 
gases.'' In addition, we are finalizing revisions to add reporting of 
an ID number or descriptor for each insulating gas and the name and 
weight percent of each insulating gas reported. The EPA has also made 
one minor clarification from proposal. We initially proposed 40 CFR 
98.456(u) to require reporting of an ID number or descriptor for each 
unique insulating gas. To clarify the applicability of this requirement 
for those gases mixed on-site, the final rule clarifies that facilities 
must report an ID number or other appropriate descriptor that is unique 
to the reported insulating gas, and for each ID number or descriptor 
reported, the name and weight percent of each fluorinated gas in the 
insulating gas. See section III.U.1. of the preamble to the 2022 Data 
Quality Improvements Proposal for additional information on these 
revisions and their supporting basis.
b. Revisions To Streamline and Improve Implementation for Subpart SS
    To account for changes in the usage of certain GHGs and reduce the 
likelihood that the reporting threshold will cover facilities with 
emissions well below 25,000 mtCO2e, we are generally 
finalizing revisions to the applicability threshold of subpart SS as 
proposed. (The one change is the introduction of the term ``reportable 
insulating gas,'' as described in this section III.Y. of the preamble.) 
The revisions remove the consumption-based threshold at 40 CFR 98.451 
and instead require facilities to estimate total annual GHG emissions 
for comparison to the 25,000 mtCO2e threshold by introducing 
a new equation, equation SS-1. The equation SS-1 continues to be based 
on the total annual purchases of insulating gases, but establishes an 
updated comparison to the threshold, and accounts for the additional 
fluorinated gases reported by industry. Potential reporters are 
required to account for the total annual purchases of all reportable 
insulating gases and multiply the purchases of each reportable 
insulating gas by the GWP for each F-GHG and the emission factor of 
0.10 (or 10 percent). The final rule threshold methodology is more 
appropriate because it represents the actual fluorinated gases used by 
a reporter; these revisions also streamline the reporting requirements 
to focus Agency resources on the substantial emission sources within 
the sector. Additionally, the changes revise the inclusion of subpart 
SS in the existing table A-3 to subpart A. Because we are providing a 
method for direct comparison to the 25,000 mtCO2e threshold, 
we are removing subpart SS from table A-3 and including the subpart in 
table A-4 to subpart A. This will require facilities to determine 
applicability according to 40 CFR 98.2(a)(2) and consider the combined 
emissions from stationary fuel combustion sources (subpart C), 
miscellaneous use of carbonates (subpart U), and other applicable 
source categories. Including subpart SS in table A-4 to subpart A is 
consistent with other GHGRP subparts that use the 25,000 
mtCO2e threshold included under 40 CFR 98.2(a)(2) to 
determine applicability. See section III.U.2. of the preamble to the 
2022 Data Quality Improvements Proposal for additional information on 
these revisions and their supporting basis.
2. Summary of Comments and Responses on Subpart SS
    This section summarizes the major comments and responses related to 
the proposed amendments to subpart SS. See the document ``Summary of 
Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart SS.
    Comment: One commenter suggested redefining the definition of 
``insulating gas'' to including any gas with a GWP greater than one and 
not any fluorinated GHG or fluorinated GHG mixture. The commenter urged 
that the proposed definition ignores other potential gases that may 
come onto the market that are not fluorinated but still have a GWP 
potential. The commenter stated that defining insulating gas under 
subpart SS to include any gas with a GWP greater than one used as an 
insulating gas and/or arc quenching gas in electrical equipment would 
mirror the threshold implemented by the California Air Resources Board 
and would provide consistency for reporters across Federal and State 
reporting rules.
    Response: In the final rule, the EPA is not requiring electrical 
equipment manufacturers and refurbishers to report emissions of 
insulating gases with weighted average 100-year GWPs of one or less, 
but the EPA is requiring such facilities to report the quantities of 
insulating gases with GWPs of one or less, as well as the nameplate 
capacity of the associated equipment, that they transfer to their 
customers. Based on a review of the subpart SS data submitted to date, 
the EPA has concluded that excluding emissions of insulating gases with 
weighted average GWPs of one or less from reporting under subpart SS 
will have little effect on the accuracy or completeness of the GWP-
weighted totals reported under subpart SS or under the GHGRP generally. 
Between 2011 and 2021, total SF6 and PFC emissions across 
all facilities reporting under subpart SS have ranged from 5 to 15 mt 
(unweighted) or 120,000 to 350,000 mtCO2e. At GWPs of one, 
these weighted totals would be equivalent to the unweighted quantities 
reported, which constitute approximately 0.004% (1/23,500) of the GWP-
weighted totals. Even in a worst-case scenario where the annual 
manufacturer emissions of a very low-GWP insulating gas were assumed to 
equal the total quantity of that gas transferred from manufacturers to 
customers (implying an emission rate of 100%, higher than any ever 
reported under subpart SS), the total GWP-weighted emissions reported 
under subpart SS would be considerably smaller than those reported 
under any other subpart: total unweighted quantities shipped to 
customers reported across all facilities to date have ranged between 
196 and 372 mt. At GWPs of 1, these totals would fall well below the 
15,000- and 25,000 mtCO2e quantities below which individual 
facilities are eventually allowed to exit the program under the off-
ramp provisions of subpart A of part 98 (40 CFR 98.2(i)), as 
applicable.
    While the EPA is not requiring electrical equipment manufacturers 
and refurbishers to report their emissions of insulating gases with 
GWPs of one or less, the EPA is requiring such facilities to report the 
quantities of insulating gases with weighted average GWPs of one or 
less, as well as the nameplate capacity of the associated equipment, 
that they transfer to their customers. Tracking such transfers is 
important to understanding the extent to which substitutes for 
SF6 are replacing SF6 as an insulating gas, which 
will inform future policies and programs under provisions of the CAA. 
The EPA

[[Page 31865]]

anticipates that tracking transfers to customers will involve a lower 
burden than tracking emissions and other quantities in addition to 
transfers.

Z. Subpart UU--Injection of Carbon Dioxide

    We are finalizing the amendments to subpart UU of part 98 
(Injection of Carbon Dioxide) as revised in the 2023 Supplemental 
Proposal. This section discusses the final revisions to subpart UU. The 
EPA received only one supportive comments on the proposed revision to 
subpart UU in the 2023 Supplemental Proposal. See the document 
``Summary of Public Comments and Responses for 2024 Final Revisions and 
Confidentiality Determinations for Data Elements under the Greenhouse 
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a 
complete listing of all comments and responses related to subpart UU.
    The EPA initially proposed amendments to subpart UU in the 2022 
Data Quality Improvements Proposal that were intended to harmonize with 
revisions to add new subpart VV to part 98 (Geologic Sequestration of 
Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916). Subpart VV 
is described further in section III.Z. of this preamble. However, we 
received comments on the 2022 Data Quality Improvements Proposal saying 
that the applicability of proposed subpart VV was unclear. The EPA 
subsequently re-proposed revisions to 40 CFR 98.470 in the 2023 
Supplemental Proposal. As described in sections III.O. of the preamble 
of the 2023 Supplemental Proposal, the EPA proposed, and is finalizing, 
revisions to Sec.  98.470 of subpart UU of part 98 to clarify the 
applicability of each subpart when a facility quantifies their geologic 
sequestration of CO2 in association with EOR operations 
through the use of the CSA/ANSI ISO 27916:19 method. Specifically, we 
are clarifying that facilities with a well or group of wells that must 
report under subpart VV shall not also report data for those same wells 
under subpart UU. These changes also clarify how CO2-EOR 
projects that may transition to use of the CSA/ANSI ISO 27916:19 method 
during a reporting year will be required to report for the portion of 
the reporting year before they began using CSA/ANSI ISO 27916:19 and 
for the portion after they began using CSA/ANSI ISO 27916:19. 
Additional rationale for these amendments is available in the preamble 
to the 2023 Supplemental Proposal.

AA. Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced 
Oil Recovery Using ISO 27916

    We are finalizing several amendments to add subpart VV (Geologic 
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 
27916) to part 98 as proposed. Section III.Z.1. of this preamble 
discusses the final requirements of subpart VV. The EPA received 
several comments on the proposed subpart VV which are discussed in 
section III.V.2. of this preamble. We are also finalizing as proposed 
related confidentiality determinations for data elements resulting from 
the revisions to subpart VV as described in section VI. of this 
preamble.
1. Summary of Final Amendments to Subpart VV
    This section summarizes the substantive final amendments to subpart 
VV. Major changes to the final rule as compared to the proposed 
revisions are identified in this section. The rationale for these and 
any other changes to 40 CFR part 98, subpart VV can be found in this 
section. Additional rationale for these amendments is available in the 
preamble to the 2022 Data Quality Improvements Proposal 2023 
Supplemental Proposal.
a. Source Category Definition
    In the 2022 Data Quality Improvements Proposal, the EPA proposed 
adding a new source category, subpart VV, to part 98 to add calculation 
and reporting requirements for quantifying geologic sequestration of 
CO2 in association with EOR operations, which would only 
apply to facilities that quantify the geologic sequestration of 
CO2 in association with EOR operations in conformance with 
the ISO standard designated as CSA/ANSI ISO 27916:19, Carbon dioxide 
capture, transportation and geological storage--Carbon dioxide storage 
using enhanced oil recovery.\42\ In our initial proposal, the EPA 
outlined the source category definition, rationale for no threshold, 
calculation methodology, and monitoring, recordkeeping, and reporting 
requirements. We noted at that time that under existing GHGRP 
requirements, facilities that receive CO2 for injection at 
EOR operations report under subpart UU (Injection of Carbon Dioxide), 
and facilities that geologically sequester CO2 through EOR 
operations may instead opt-in to subpart RR (Geologic Sequestration of 
Carbon Dioxide). The EPA proposed to add new subpart VV to require 
reporting of incidental CO2 storage associated with EOR 
based on the CSA/ANSI ISO 27916:19 standard. We subsequently received 
detailed comments saying that the applicability of proposed subpart VV 
was unclear, specifically, proposed 40 CFR 98.480 ``Definition of the 
Source Category.'' The commenters were uncertain whether the EPA had 
intended to require facilities using CSA/ANSI ISO 27916:19 to report 
under subpart VV or whether facilities that used CSA/ANSI ISO 27916:19 
would have the option to choose under which subpart they would report 
to: subpart RR, subpart UU, or subpart VV.
---------------------------------------------------------------------------

    \42\ Although the title of the standard references only EOR, 
Clause 1.1 of CSA/ANSI ISO 27916:19 indicates that the standard can 
apply to enhanced gas recovery as well. Therefore, any reference to 
EOR in subpart VV also applies to enhanced gas recovery.
---------------------------------------------------------------------------

    In the 2023 Supplemental Proposal, the EPA subsequently reproposed 
Sec. Sec.  98.480 and 98.481 of subpart VV to clarify the applicability 
to each subpart. As explained in section III.P. of the preamble the 
2023 Supplemental Proposal, the EPA clarified that if a facility elects 
to use the CSA/ANSI ISO 27916:19 method for quantifying geologic 
sequestration of CO2 in association with EOR operations, 
then the facility would be required under the GHGRP to report under new 
subpart VV (unless the facility chooses to report under subpart RR and 
has received an approved Monitoring, Reporting, and Verification Plan 
(MRV Plan) from EPA). The EPA further clarified that subpart VV is not 
intended to apply to facilities that use the content of CSA/ANSI ISO 
27916:19 for a purpose other than demonstrating secure geologic 
storage, such as only as a reference material or for informational 
purposes. Following review of subsequent comments received on the 
reproposed source category definition, we are finalizing the definition 
of the source category as proposed in the 2023 Supplemental Proposal.
b. Reporting Threshold
    In the 2022 Data Quality Improvements Proposal, the EPA proposed no 
threshold for reporting under subpart VV (i.e., that subpart VV would 
be an ``all-in'' reporting subpart). The EPA also proposed under 40 CFR 
98.480(c) that facilities subject only to subpart VV would not be 
required to report emissions under subpart C or any other subpart 
listed in 40 CFR 98.2(a)(1) or (2), consistent with the requirements 
for existing reporters under subpart UU. In the 2023 Supplemental 
Proposal, the EPA maintained no threshold is required for reporting, 
but amended the regulatory text to clarify that all CO2-

[[Page 31866]]

EOR projects using CSA/ANSI ISO 27916:19 as a method of quantifying 
geologic sequestration that do not report under subpart RR would report 
under subpart VV. We also proposed text at 40 CFR 98.481(c) to clarify 
how CO2-EOR projects previously reporting under subpart UU 
that begin using CSA/ANSI ISO 27916:19 part-way through a reporting 
year must report. The EPA is finalizing these requirements as 
reproposed in the 2023 Supplemental Proposal.
    Additionally, we are finalizing revisions at 40 CFR 98.481(b) that 
facilities subject to subpart VV will not be subject to the off-ramp 
requirements of 40 CFR 98.2(i). Instead, once a facility opts-in to 
subpart VV, the owner or operator must continue for each year 
thereafter to comply with all requirements of the subpart, including 
the requirement to submit annual reports, until the facility 
demonstrates termination of the CO2-EOR project following 
the requirements of CSA/ANSI ISO 27916:19. The operator must notify the 
Administrator of its intent to cease reporting and provide a copy of 
the CO2-EOR project termination documentation prepared for 
CSA/ANSI ISO 27916:19.
c. Calculation Methods
    In the 2022 Data Quality Improvements Proposal and 2023 
Supplemental Proposal, the EPA proposed incorporating the 
quantification methodology of CSA/ANSI ISO 27916:19 for calculation of 
emissions. Under CSA/ANSI ISO 27916:19, the mass of CO2 
stored is determined as the total mass of CO2 received minus 
the total mass of CO2 lost from project operations and the 
mass of CO2 lost from the EOR complex. The EOR complex is 
defined as the project reservoir, trap, and such additional surrounding 
volume in the subsurface as defined by the operator within which 
injected CO2 will remain in safe, long-term containment. 
Specific losses include those from leakage from production, handling, 
and recycling facilities; from infrastructure (including wellheads); 
from venting/flaring from production operations; and from entrainment 
within produced gas/oil/water when this CO2 is not separated 
and reinjected. We are finalizing the calculation requirements as 
proposed.
d. Monitoring, QA/QC, and Verification Requirements
    The EPA is finalizing as proposed the requirement for reporters to 
use the applicable monitoring and quality assurance requirements set 
forth in CSA/ANSI ISO 27916:19.
e. Procedures for Estimating Missing Data
    The EPA is finalizing as proposed the requirement for reporters to 
use the applicable missing data and quality assurance procedures set 
forth in CSA/ANSI ISO 27916:19.
f. Data Reporting Requirements
    The EPA is finalizing, as proposed, that facilities will report the 
amount of CO2 stored, inputs included in the mass balance 
equation used to determine CO2 stored using the CSA/ANSI ISO 
27916:19 methodology, and documentation providing the basis for that 
determination as set forth in CSA/ANSI ISO 27916:19. Documentation 
includes providing the CSA/ANSI ISO 27916:19 EOR Operations Management 
Plan (OMP), which is required to specify: (1) a geological description 
of the site and the procedures for field management and operational 
containment during the quantification period; (2) the initial 
containment assurance plan to identify potential leakage pathways; (3) 
the plan for monitoring of potential leakage pathways; and (4) the 
monitoring methods for detecting and quantifying losses and how this 
will serve to provide the inputs into site-specific mass balance 
equations. Reporters must also specify any changes made to containment 
assurance and monitoring approaches and procedures in the EOR OMP made 
within the reporting year.
    We are also finalizing the reporting of the following information 
per CSA/ANSI ISO 27916:19: (1) the quantity of CO2 stored 
during the year; (2) the formula and data used to quantify the storage, 
including the quantity of CO2 delivered to the 
CO2-EOR project and losses during the year; (3) the methods 
used to estimate missing data and the amounts estimated; (4) the 
approach and method for quantification utilized by the operator, 
including accuracy, precision and uncertainties; (5) a statement 
describing the nature of validation or verification, including the date 
of review, process, findings, and responsible person or entity; and (6) 
the source of each CO2 stream quantified as storage. The 
final rule also requires that reporters provide a copy of the 
independent engineer or geologist's certification as part of reporting 
to subpart VV, if such a certification has been made.
    Finally, the EPA is finalizing a notification for project 
termination. The final rule specifies that the time for cessation of 
reporting under subpart VV is the same as under CSA/ANSI ISO 27916:19; 
the operator must notify the Administrator of its intent to cease 
reporting and provide a copy of the CO2-EOR project 
termination documentation.
g. Records That Must Be Retained
    The EPA is finalizing as proposed the requirement that reporters 
meet the record retention requirements of 40 CFR 98.3(g) and the 
applicable recordkeeping retention requirements set forth in CSA/ANSI 
ISO 27916:19.
2. Summary of Comments and Responses on Subpart VV
    The EPA received several comments for subpart VV; the majority of 
these comments were received on the 2022 Data Quality Improvements 
Proposal and were previously addressed in the preamble to the 2023 
Supplemental Proposal (see section III.P. of the preamble to the 2023 
Supplemental Proposal). The EPA received only supportive comments on 
the proposed revisions to subpart VV in the 2023 Supplemental Proposal; 
see the document ``Summary of Public Comments and Responses for 2024 
Final Revisions and Confidentiality Determinations for Data Elements 
under the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-
2019-0424 for a complete listing of all comments and responses related 
to subpart VV.

BB. Subpart WW --Coke Calciners

    We are finalizing the addition of subpart WW to part 98 (Coke 
Calciners) with revisions in some cases. Section III.BB.1. of this 
preamble discusses the final requirements of subpart WW. The EPA 
received several comments on the proposed subpart WW which are 
discussed in section III.BB.2. of this preamble. We are also finalizing 
as proposed related confidentiality determinations for data elements 
resulting from the revisions to subpart WW as described in section VI. 
of this preamble.
1. Summary of Final Amendments to Subpart WW
    This section summarizes the substantive final amendments to subpart 
WW. Major changes in this final rule as compared to the proposed 
revisions are identified in this section. The rationale for these and 
any other changes to 40 CFR part 98, subpart WW can be found in this 
section. Additional rationale for these amendments is available in the 
preamble to the 2022 Data Quality Improvements Proposal and 2023 
Supplemental Proposal.

[[Page 31867]]

a. Source Category Definition
    The EPA is finalizing the source category definition as proposed, 
with one minor clarification. Specifically, we proposed that the coke 
calciner source category consists of process units that heat petroleum 
coke to high temperatures in the absence of air or oxygen for the 
purpose of removing impurities or volatile substances in the petroleum 
coke feedstock. Following review of comments received, the EPA is 
revising the source category definition from that proposed to remove 
the language ``in the absence of air or oxygen.'' See section III.BB.2. 
of this preamble for additional information on related comments and the 
EPA's response. The final definition of the coke calciner source 
category includes, but is not limited to, rotary kilns or rotary hearth 
furnaces used to calcine petroleum coke and any afterburner or other 
equipment used to treat the process gas from the calciner. The source 
category includes all coke calciners, not just those co-located at 
petroleum refineries, to provide consistent requirements for all coke 
calciners.
b. Reporting Threshold
    In the 2023 Supplemental Proposal, the EPA proposed no threshold 
for reporting under subpart WW. Because coke calciners are large 
emission sources, they are expected to emit over the 25,000 
mtCO2e threshold generally required to report under existing 
GHGRP subparts with thresholds, and nearly all of them are also 
projected to exceed the 100,000 mtCO2e threshold. Therefore, 
the EPA projects that there are limited differences in the number of 
reporting facilities based on any of the emission thresholds 
considered. For this reason, the EPA is finalizing the coke calciner 
source category as an ``all-in'' subpart (i.e., regardless of their 
emissions profile).
c. Calculation Methods
    Coke calciners primarily emit CO2, but also have 
CH4 and N2O emissions as part of the process gas 
emission control combustion device operation. The EPA is finalizing, as 
proposed in the 2023 Supplemental Proposal, that CO2, 
CH4, and N2O emissions from each coke calcining 
unit be estimated.
    The EPA reviewed a number of different emissions estimation methods 
for coke calciners. We subsequently proposed, and are finalizing, to 
require either one of two separate calculation methods, the use of a 
CEMS or the carbon mass balance method for estimating emissions. Each 
of these methodologies are used to estimate CO2 emissions. 
We are also finalizing, as proposed, that coke calciners also estimate 
process CH4 and N2O emissions based on the total 
CO2 emissions determined for the coke calciner and the ratio 
of the default CO2 emission factor for petroleum coke in 
table C-1 to subpart C of part 98 to the default CH4 and 
N2O emission factors for petroleum products in table C-2 to 
subpart C of part 98. Under the final methods, petroleum refineries 
with coke calciners are able to maintain their current calculation 
methods. Additional detail on the calculation methods reviewed are 
available in section IV.B. of the preamble to the 2023 Supplemental 
Proposal.
    Direct measurement using CEMS. The CEMS approach directly measures 
CO2 concentration and total exhaust gas flow rate for the 
combined process and combustion source emissions. CO2 mass 
emissions are calculated from these measured values using equation C-6 
and, if necessary, equation C-7 in 40 CFR 98.33(a)(4).
    The EPA proposed that the CEMS method under subpart WW would be 
implemented consistent with subpart Y of part 98 (Petroleum 
Refineries), which required reporters to determine CO2 
emissions from auxiliary fuel use discharged in the coke calciner 
exhaust stack using methods in subpart C of part 98, and to subtract 
those emissions from the measured CEMS emissions to determine the 
process CO2 emissions. We are finalizing this requirement.
    Carbon balance method. For those facilities that do not have a 
qualified CEMS in-place, facilities may use the carbon mass balance 
method, using data that is expected to be routinely monitored by coke 
calcining facilities. The carbon mass balance method uses the mass of 
green coke, calcined coke and petroleum coke dust removed from the dust 
collection system, along with the carbon content of the green and 
calcined coke, to estimate process CO2 emissions; the 
methodology is the same as current equation Y-13 of 40 CFR 98.253(g)(2) 
that is used for coke calcining processes co-located at petroleum 
refineries.
d. Monitoring, QA/QC, and Verification Requirements
    The EPA is finalizing the monitoring methods to subpart WW as 
proposed.
    Direct measurement using CEMS. For direct measurement using CEMS, 
the CEMS method requires both a continuous CO2 concentration 
monitor and a continuous volumetric flow monitor. Reporters required to 
or electing to use CEMS must install, operate, and calibrate the 
monitoring system according to subpart C (General Stationary Fuel 
Combustion Sources), which is consistent with the current requirements 
for coke calciner CO2 CEMS monitoring requirements within 
subpart Y. We are finalizing that all CO2 CEMS and flow rate 
monitors used for direct measurement of GHG emissions should comply 
with QA/QC procedures for daily calibration drift checks and quarterly 
or annual accuracy assessments, such as those provided in Appendix F to 
part 60 or similar QA/QC procedures. These requirements ensure the 
quality of the reported GHG emissions and are consistent with the 
current requirements for CEMS measurements within subparts A (General 
Provisions) and C of the GHGRP.
    Carbon balance method. The carbon mass balance method requires 
monitoring of mass quantities of green coke fed to the process, 
calcined coke leaving the process, and coke dust removed from the 
process by dust collection systems. It also requires periodic 
determination of carbon content of the green and calcined coke. For 
coke mass measurements, we are finalizing that the measurement device 
be calibrated according to the procedures specified by the updated NIST 
HB 44-2023: Specifications, Tolerances, and Other Technical 
Requirements For Weighing and Measuring Devices, 2023 edition (we have 
clarified the title and publication date of this method in the final 
rule) or the procedures specified by the manufacturer. We are requiring 
the measurement device be recalibrated either biennially or at the 
minimum frequency specified by the manufacturer. These requirements are 
to ensure the quality of the reported GHG emissions and to be 
consistent with the current requirements for coke calciner mass 
measurements within subpart Y.
    For carbon content of coke measurements, the owner or operator must 
follow approved analytical procedures and maintain and calibrate 
instruments used according to manufacturer's instructions and to 
document the procedures used to ensure the accuracy of the measurement 
devices used. These requirements are to ensure the quality of the 
reported GHG emissions and to be consistent with the current 
requirements for coke calciner mass measurements within subpart Y. 
These determinations must be made monthly. If carbon content 
measurements are made more often than monthly, all measurements made 
within the calendar month must be used to determine the average for the 
month.

[[Page 31868]]

e. Procedures for Estimating Missing Data
    The EPA is finalizing as proposed the procedures for estimating 
missing data. For the CEMS methodology, whenever a quality-assured 
value of a required parameter is unavailable (e.g., if a CEMS 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations. For missing CEMS data, the missing data procedures 
in subpart C must be used.
    Under the carbon mass balance method, for each missing value of 
mass or carbon content of coke, reporters must use the average of the 
data measurements before and after the missing data period. If, for a 
particular parameter, no quality assured data are available prior to 
the missing data incident, the substitute data value must be the first 
quality-assured value obtained after the missing data period. 
Similarly, if no quality-assured data are available after the missing 
data incident, the substitute data value must be the most recently 
acquired quality-assured value obtained prior to the missing data 
period.
f. Data Reporting Requirements
    The EPA is finalizing the data reporting requirements of subpart WW 
as proposed. For coke calcining units, the owner and operator shall 
report the coke calciner unit ID number and maximum rated throughput of 
the unit, the method used to calculate GHG emissions, and the 
calculated CO2, CH4, and N2O annual 
emissions for each unit, expressed in metric tons of each pollutant 
emitted. We are also requiring the owner and operator to report the 
annual mass of green coke fed to the coke calcining unit, the annual 
mass of marketable petroleum coke produced by the coke calcining unit, 
the annual mass of petroleum coke dust removed from the process through 
the dust collection system of the coke calcining unit, the annual 
average mass fraction carbon content of green coke fed to the unit, and 
the annual average mass fraction carbon content of the marketable 
petroleum coke produced by the coke calcining unit.
g. Records That Must Be Retained
    The EPA is finalizing the record retention requirements of subpart 
WW as proposed. Facilities are required to maintain records documenting 
the procedures used to ensure the accuracy of the measurements of all 
reported parameters, including but not limited to, calibration of 
weighing equipment, flow meters, and other measurement devices. The 
estimated accuracy of measurements made with these devices must also be 
recorded, and the technical basis for these estimates must be provided.
    For the coke calciners source category, we are finalizing that the 
verification software specified in 40 CFR 98.5(b) be used to fulfill 
the recordkeeping requirements for the following five data elements:
     Monthly mass of green coke fed to the coke calcining unit;
     Monthly mass of marketable petroleum coke produced by the 
coke calcining unit;
     Monthly mass of petroleum coke dust removed from the 
process through the dust collection system of the coke calcining unit;
     Average monthly mass fraction carbon content of green coke 
fed to the coke calcining unit; and
     Average monthly mass fraction carbon content of marketable 
petroleum coke produced by the coke calcining unit.

2. Summary of Comments and Responses on Subpart WW

    This section summarizes the major comments and responses related to 
the proposed subpart WW. The EPA previously requested comment on the 
addition of coke calciners production source category as a new subpart 
to part 98 in the 2022 Data Quality Improvements Proposal. The EPA 
received several comments for subpart WW on the 2022 Data Quality 
Improvements Proposal; many of these comments were previously addressed 
in the preamble to the 2023 Supplemental Proposal, wherein the EPA 
proposed to add new subpart WW for coke calciners (see section IV.B. of 
the preamble to the 2023 Supplemental Proposal). The EPA received 
additional comments regarding the proposed subpart WW following the 
2023 Supplemental Proposal. See the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart WW.
    Comment: One commenter stated that the description of coke 
calciners may be overly narrow. The commenter contended that the 
language ``in the absence of air or oxygen'' is not necessarily 
accurate. The commenter stated that air/oxygen is necessary for 
combustion to occur, and that the high temperatures required for proper 
calcination are from the combustion of volatiles and carbon in the 
green coke.
    Response: We understand that air is introduced in the coke calciner 
to burn the volatiles from the coke, but the air is introduced in a 
limited fashion (limited oxygen) so that the complete combustion of 
coke in the calciner does not occur. However, we agree with the 
commenter that the phrase ``in the absence of air or oxygen'' may be 
too restrictive and we have deleted this phrase from the proposed 
source category description at 40 CFR 98.490(a) in the final rule.
    Comment: One commenter stated that coke calciners that use refinery 
fuel gas or natural gas during startup or during hot standby should be 
allowed to report emissions from these fuel gases using a methodology 
from subpart C of part 98, separately from the coke calciner emissions. 
The commenter stated that where coke calcining and fuel gas combustion 
are occurring simultaneously, the fuel gas emissions should be 
subtracted from the emissions that are calculated using CEMS and the 
proposed stack flow methodology to avoid double counting. The commenter 
added that the requirements for fuel gas or natural gas composition and 
heat content use in coke calciners should be the same as required in 
subpart C.
    Response: We agree with the commenter and the issues identified by 
the commenter were addressed in the 2023 Supplemental Proposal. We are 
finalizing these provisions for treating GHG emissions from auxiliary 
fuel use as proposed (see 40 CFR 98.493(b)(1)).

CC. Subpart XX--Calcium Carbide Production

    We are finalizing the addition of subpart XX (Calcium Carbide 
Production) to part 98 as proposed. Section III.CC.1. of this preamble 
discusses the final requirements of subpart XX. The EPA received 
comments on the proposed subpart XX which are discussed in section 
III.CC.2. of this preamble. We are also finalizing as proposed related 
confidentiality determinations for data elements resulting from the 
addition of subpart XX as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart XX
    This section summarizes the final amendments to subpart XX. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart XX can be found in this section and 
section III.CC.2. of this preamble.

[[Page 31869]]

Additional rationale for these amendments is available in the preamble 
to the 2022 Data Quality Improvements Proposal and 2023 Supplemental 
Proposal.
a. Source Category Definition
    The EPA is finalizing the source category definition as proposed. 
We are defining calcium carbide production to include any process that 
produces calcium carbide. Calcium carbide is an industrial chemical 
manufactured from lime (CaO) and carbon, usually petroleum coke, by 
heating the mixture to 2,000 to 2,100 C (3,632 to 3,812 [deg]F) in an 
electric arc furnace. During the production of calcium carbide, the use 
of carbon-containing raw materials (petroleum coke) results in 
emissions of CO2.
    Although we considered accounting for emissions from the production 
of acetylene at calcium carbide facilities in the 2022 Data Quality 
Improvements Proposal, we ultimately determined that acetylene is not 
produced at the one known plant that produces calcium carbide. For this 
reason, in the 2023 Supplemental Proposal we did not propose, and as 
such are not taking final action on, inclusion of reporting of 
CO2 emissions from the production of acetylene from calcium 
carbide under subpart XX.
b. Reporting Threshold
    In the 2023 Supplemental Proposal, the EPA proposed no threshold 
for reporting under subpart XX. The current estimate of emissions from 
the single known calcium carbide production facility in the United 
States exceeds 25,000 mtCO2e by a factor of about 1.9. 
Therefore we are finalizing, as proposed, the calcium carbide source 
category as an ``all-in'' subpart. For a full discussion of the 
threshold analysis, please refer to section IV.C. of the preamble to 
the 2023 Supplemental Proposal.
c. Calculation Methods
    In the 2023 Supplemental Proposal, the EPA reviewed the production 
processes and available emissions estimation methods for calcium 
carbide production including a default emission factor methodology, a 
carbon balance methodology (IPCC Tier 3), and direct measurement using 
CEMS (see section IV.C.5. of the preamble to the 2023 Supplemental 
Proposal). We subsequently proposed and are finalizing two different 
methods for quantifying GHG emissions from calcium carbide 
manufacturing, depending on current emissions monitoring at the 
facility. If a qualified CEMS is in place, the CEMS must be used. 
Otherwise, the facility can elect to either install a CEMS or elect to 
use the carbon mass balance method.
    Direct measurement using CEMS. Facilities with an existing CEMS 
that meet the requirements outlined in subpart C of part 98 (General 
Stationary Fuel Combustion) are required to use CEMS to estimate 
combined process and combustion CO2 emissions. Facilities 
are required to follow the requirements of subpart C to estimate all 
CO2 emissions from the industrial source. Facilities will be 
required to follow subpart C to estimate emissions of CO2, 
CH4, and N2O from stationary combustion.
    Carbon balance method. For facilities that do not have CEMS that 
meet the requirements of 40 CFR part 98 subpart C, the alternate 
monitoring method is the carbon balance method. For any stationary 
combustion units included at the facility, facilities will be required 
to follow the existing requirements at 40 CFR part 98, subpart C to 
estimate emissions of CO2, CH4, and 
N2O from stationary combustion. Use of facility specific 
information is consistent with IPCC Tier 3 methods and is the preferred 
method for estimating emissions for other GHGRP sectors.
d. Monitoring, QA/QC, and Verification requirements
    The EPA is finalizing the monitoring, QA/QC, and verification 
requirements to subpart XX as proposed. We are finalizing two separate 
monitoring methods: direct measurement and a mass balance emission 
calculation.
    Direct measurement using CEMS. For facilities where process 
emissions and/or combustion GHG emissions are contained within a stack 
or vent, facilities can take direct measurement of the GHG 
concentration in the stack gas and the flow rate of the stack gas using 
a CEMS. Under the final rule, if facilities use an existing CEMS to 
meet the monitoring requirements, they are required to use CEMS to 
estimate CO2 emissions. Where the CEMS capture all 
combustion- and process-related CO2 emissions, facilities 
will be required to follow the requirements of subpart C to estimate 
emissions.
    The CEMS method requires both a continuous CO2 
concentration monitor and a continuous volumetric flow monitor. To 
qualify as a CEMS, the monitors are required to be installed, operated, 
and calibrated according to subpart C of part 98 (40 CFR 98.33(a)(4)), 
which is consistent with CEMS requirements in other GHGRP subparts.
    Carbon balance method. For facilities using the carbon mass balance 
method, we are requiring the facility to determine the annual mass for 
each material used for the calculations of annual process 
CO2 emissions by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    For the carbon content of the materials used to calculate process 
CO2 emissions, we are finalizing a requirement that the 
owner or operator determine the carbon content using material supplier 
information or collect and analyze at least three representative 
samples of the material inputs and outputs each year. The final rule 
will require the carbon content be analyzed at least annually using 
standard ASTM methods, including their QA/QC procedures. To reduce 
burden, if a specific process input or output contributes less than one 
percent of the total mass of carbon into or out of the process, the 
reporter does not have to determine the monthly mass or annual carbon 
content of that input or output.
e. Procedures for Estimating Missing Data
    We are finalizing as proposed the use of substitute data whenever a 
quality-assured value of a parameter is used to calculate emissions is 
unavailable, or ``missing.'' If the carbon content analysis of carbon 
inputs or outputs is missing, the substitute data value will be based 
on collected and analyzed representative samples for average carbon 
contents. If the monthly mass of carbon-containing inputs and outputs 
is missing, the substitute data value will be based on the best 
available estimate of the mass of the inputs and outputs from all 
available process data or data used for accounting purposes, such as 
purchase records. The likelihood for missing process input or output 
data is low, as businesses closely track their purchase of production 
inputs. These missing data procedures are the same as those for the 
ferroalloy production source category, subpart K of part 98, under 
which the existing U.S. calcium carbide production facility currently 
reports.
f. Data Reporting Requirements
    The EPA is finalizing, as proposed, that each carbon carbide 
production facility report the annual CO2 emissions

[[Page 31870]]

from each calcium carbide production process, as well as any stationary 
fuel combustion emissions. In addition, we are finalizing requirements 
for facilities to provide additional information that forms the basis 
of the emissions estimates, along with supplemental data, so that we 
can understand and verify the reported emissions. All calcium carbide 
production facilities will be required to report their annual 
production and production capacity, total number of calcium carbide 
production process units, annual consumption of petroleum coke, each 
end use of any calcium carbide produced and sent off site, and, if the 
facility produces acetylene, the annual production of acetylene, the 
quantity of calcium carbide used for acetylene production at the 
facility, and the end use of the acetylene produced on-site. The EPA is 
also finalizing reporting the end use of calcium carbide sent off site, 
as well as acetylene production information for current or future 
calcium carbide production facilities, to inform future Agency policy 
under the CAA.
    As proposed, we are finalizing requirements that if a facility uses 
CEMS to measure their CO2 emissions, they will be required 
to also report the identification number of each process unit; the EPA 
is clarifying in the final rule that if a facility uses CEMS, emissions 
are reported from each CEMS monitoring location. If a CEMS is not used 
to measure CO2 emissions, the facility will also report the 
method used to determine the carbon content of each material for each 
process unit, how missing data were determined, and the number of 
months missing data procedures were used.
g. Records That Must Be Retained
    The EPA is finalizing as proposed the requirement that facilities 
maintain records of information used to determine the reported GHG 
emissions, to allow us to verify that GHG emissions monitoring and 
calculations were done correctly. If a facility uses a CEMS to measure 
their CO2 emissions, they will be required to record the 
monthly calcium carbide production from each process unit and the 
number of monthly and annual operating hours for each process unit. If 
a CEMS is not used, the facility will be required to retain records of 
monthly production, monthly and annual operating hours, monthly 
quantities of each material consumed or produced, and carbon content 
determinations.
    As proposed, we are finalizing requirements that the owner or 
operator maintain records of how measurements are made, including 
measurements of quantities of materials used or produced and the carbon 
content of process input and output materials. The procedures for 
ensuring accuracy of measurement methods, including calibration, must 
be recorded.
    The final rule also requires the retention of a record of the file 
generated by the verification software specified in 40 CFR 98.5(b) 
including:
     Carbon content (percent by weight expressed as a decimal 
fraction) of the reducing agent (petroleum coke), carbon electrode, 
product produced, and nonproduct outgoing materials; and
     Annual mass (tons) of the reducing agent (petroleum coke), 
carbon electrode, product produced, and nonproduct outgoing materials.
2. Summary of Comments and Responses on Subpart XX
    The EPA previously requested comment on the addition of a calcium 
carbide source category as a new subpart to part 98 in the 2022 Data 
Quality Improvements Proposal. The EPA received one comment objecting 
to the addition of the proposed source category and one comment on the 
potential calculation methodology. Subsequently, the EPA responded to 
the comments and proposed to add new subpart XX for calcium carbide 
(see section IV.C. of the preamble to the 2023 Supplemental Proposal). 
The EPA received no comments regarding proposed subpart XX following 
the 2023 Supplemental Proposal. See the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart XX.

DD. Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid Production

    We are finalizing the addition of subpart YY (Caprolactam, Glyoxal, 
and Glyoxylic Acid Production) to part 98 with revisions in some cases. 
Section III.DD.1. of this preamble discusses the final requirements of 
subpart YY. Major comments, as applicable, are addressed in section 
III.DD.2. of this preamble. We are also finalizing as proposed related 
confidentiality determinations for data elements resulting from the 
revisions to subpart YY as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart YY
    This section summarizes the substantive final amendments to subpart 
YY. Major changes to the final rule as compared to the proposed 
revisions are identified in this section. The rationale for these and 
any other changes to 40 CFR part 98, subpart YY can be found in this 
section. Additional rationale for these amendments is available in the 
preamble to the 2022 Data Quality Improvements Proposal and 2023 
Supplemental Proposal.
a. Source Category Definition
    In the 2023 Supplemental Proposal, the EPA proposed that the 
caprolactam, glyoxal, or glyoxylic acid source category, as defined 
under subpart YY, would include any facility that produces caprolactam, 
glyoxal, or glyoxylic acid.
    Caprolactam is a crystalline solid organic compound with a wide 
variety of uses, including brush bristles, textile stiffeners, film 
coatings, synthetic leather, plastics, plasticizers, paint vehicles, 
cross-linking for polyurethanes, and in the synthesis of lysine. 
Caprolactam is primarily used in the manufacture of synthetic fibers, 
especially Nylon 6.
    Glyoxal is a solid organic compound with a wide variety of uses, 
including as a crosslinking agent in various polymers for paper 
coatings, textile finishes, adhesives, leather tanning, cosmetics, and 
oil-drilling fluids; as a sulfur scavenger in natural gas sweetening 
processes; as a biocide in water treatment; to improve moisture 
resistance in wood treatment; and as a chemical intermediate in the 
production of pharmaceuticals, dyestuffs, glyoxylic acid, and other 
chemicals. It is also used as a less toxic substitute for formaldehyde 
in some applications (e.g., in wood adhesives and embalming fluids).
    Glyoxylic acid is a solid organic compound exclusively produced by 
the oxidation of glyoxal with nitric acid. It is used mainly in the 
synthesis of vanillin, allantoin, and several antibiotics like 
amoxicillin, ampicillin, and the fungicide azoxystrobin.
    We are finalizing the source category definition to include any 
facility that produces caprolactam, glyoxal, or glyoxylic acid as 
proposed. The source category will exclude the production of glyoxal 
through the LaPorte process (i.e., the gas-phase catalytic oxidation of 
ethylene glycol with air in the presence of a silver or copper 
catalyst). As explained in the 2023 Supplemental Proposal, the LaPorte 
process does not

[[Page 31871]]

emit N2O and there are no methods for estimating 
CO2 in available literature.
b. Reporting Threshold
    In the 2023 Supplemental Proposal, the EPA proposed no threshold 
for reporting under subpart YY (i.e., that subpart YY would be an 
``all-in'' reporting subpart). The EPA noted that the total process 
emissions from current production of caprolactam, glyoxal, and 
glyoxylic acid are estimated at 1.2 million mtCO2e, largely 
from two known caprolactam production facilities; although the known 
universe of facilities that produce caprolactam, glyoxal, and glyoxylic 
acid in the United States is four to six total facilities. We proposed 
that adding caprolactam, glyoxal, and glyoxylic acid production as an 
``all-in'' subpart (i.e., regardless of the facility emissions profile) 
is a conservative approach to gather information from as many 
facilities that produce caprolactam, glyoxal, and glyoxylic acid as 
possible, especially if production of glyoxal and glyoxylic acid 
increase in the near future. The EPA is finalizing these requirements 
as proposed.
c. Calculation Methods
    In the 2023 Supplemental Proposal, the EPA reviewed the production 
processes and available emissions estimation methods for caprolactam, 
glyoxal, and glyoxylic acid production and proposed that only 
N2O emissions would be estimated from these processes. The 
EPA also proposed to require the reporting of combustion emissions from 
facilities that produce caprolactam, glyoxal, and glyoxylic acid, 
including CO2, CH4, and N2O.
    The EPA reviewed two methods from the 2006 IPCC Guidelines,\43\ 
including the Tier 2 and Tier 3 methodologies, for calculating 
N2O emissions from the production of caprolactam, glyoxal, 
and glyoxylic acid, and subsequently proposed the IPCC Tier 2 approach 
to quantify N2O process emissions. We are finalizing the 
N2O calculation requirements as proposed, with minor 
revisions. Following the Tier 2 approach established by the IPCC, 
reporters will apply default N2O generation factors on a 
site-specific basis. This requires raw material input to be known in 
addition to a standard N2O generation factor, which differs 
for each of the three chemicals. In addition, Tier 2 requires site-
specific knowledge of the use of N2O control technologies. 
The volume or mass of each product is measured with a flow meter or 
weigh scales. The process-related N2O emissions are 
estimated by multiplying the generation factor by the production and 
the destruction efficiency of any N2O control technology. 
The EPA is revising the final rule to adjust the N2O 
generation factors (proposed in table 1 to subpart YY) for glyoxal and 
glyoxylic acid production to correctly reflect the conversion of the 
IPCC default emission factors, which were intended to be converted from 
metric tons N2O emitted per metric ton of product produced 
to kg N2O per metric ton of product produced using a 
conversion factor of 1,000 kg per metric ton. The final rule corrects 
the generation factor for glyoxal from 5,200 to 520 and, for glyoxylic 
acid, from 1,000 to 100. The EPA is finalizing a minor clarification to 
equation 1 to 40 CFR 98.513(d)(2) (proposed as equation YY-1) to re-
order the defined parameters of the equation to follow their order of 
appearance in the equation. The EPA is also finalizing an additional 
equation (equation 3 to 40 CFR 98.513(f)) from the proposed rule, which 
sums the monthly process emissions estimated by equation 2 to 40 CFR 
98.513(e) (proposed as equation YY-2) to an annual value. This 
additional equation clarifies the methodology for reporting annual 
emissions and does not require the collection of any additional data.
---------------------------------------------------------------------------

    \43\ IPCC 2006. IPCC Guidelines for National Greenhouse Gas 
Inventories, Volume 3, Industrial Processes and Product Use. Chapter 
3, Chemical Industry Emissions. 2006. www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_3_Ch3_Chemical_Industry.pdf.
---------------------------------------------------------------------------

    For any stationary combustion units included at the facility, we 
proposed that facilities would be required to follow the existing 
requirements in 40 CFR part 98, subpart C to calculate emissions of 
CO2, CH4 and N2O from stationary 
combustion. We are finalizing the combustion calculation requirements 
as proposed.
d. Monitoring, QA/QC, and Verification Requirements
    Monitoring is required to comply with the N2O 
calculation methodologies for reporters that produce caprolactam, 
glyoxal, and glyoxylic acid. In the 2023 Supplemental Proposal, the EPA 
proposed that reporters that produce caprolactam, glyoxal, and 
glyoxylic acid are to determine the monthly and annual production 
quantities of each chemical and to determine the N2O 
destruction efficiency of any N2O abatement technologies in 
use. The EPA is finalizing as proposed the requirement for reporters to 
either perform direct measurement of production quantities or to use 
existing plant procedures to determine production quantities. E.g., the 
production rate can be determined through sales records or by direct 
measurement using flow meters or weigh scales.
    For determination of the N2O destruction efficiency, we 
are finalizing as proposed the requirement that reporters estimate the 
destruction efficiency for each N2O abatement technology. 
The destruction efficiency can be determined by using the 
manufacturer's specific destruction efficiency or estimating the 
destruction efficiency through process knowledge. Documentation of how 
process knowledge was used to estimate the destruction efficiency is 
required. Examples of information that could constitute process 
knowledge include calculations based on material balances, process 
stoichiometry, or previous test results provided that the results are 
still relevant to the current vent stream conditions.
    For the caprolactam, glyoxal, and glyoxylic acid production 
subpart, we are requiring reporters to perform all applicable flow 
meter calibration and accuracy requirements and maintain documentation 
as specified in 40 CFR 98.3(i).
e. Procedures for Estimating Missing Data
    For caprolactam, glyoxal, and glyoxylic acid production, the EPA is 
finalizing as proposed the requirement that substitute data for each 
missing production value is the best available estimate based on all 
available process data or data used for accounting purposes (such as 
sales records). For the control device destruction efficiency, assuming 
that the control device operation is generally consistent from year to 
year, the substitute data value should be the most recent quality 
assured value.
f. Data Reporting Requirements
    The EPA is finalizing, as proposed, that facilities must report 
annual N2O emissions (in metric tons) from each production 
line. In addition, facilities must submit the following data to 
facilitate understanding of the emissions data and verify the 
reasonableness of the reported emissions: number of process lines; 
annual production capacity; annual production; number of operating 
hours in the calendar year for each process line; abatement technology 
used and installation dates (if applicable); abatement utilization 
factor for each process line; number of times in the reporting year 
that missing data procedures were followed to measure production 
quantities of caprolactam, glyoxal, or glyoxylic acid (months); and

[[Page 31872]]

overall percent N2O reduction for each chemical for all 
process lines.
g. Records That Must Be Retained
    The EPA is finalizing as proposed the requirement that facilities 
maintain records documenting the procedures used to ensure the accuracy 
of the measurements of all reported parameters, including but not 
limited to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided. We are also requiring, as proposed, that 
facilities maintain records documenting the estimate of production rate 
and abatement technology destruction efficiency through accounting 
procedures and process knowledge, respectively.
    Finally, the EPA is also requiring, as proposed, the retention of a 
record of the file generated by the verification software specified in 
40 CFR 98.5(b) including:
     Monthly production quantities of caprolactam from all 
process lines;
     Monthly production quantities of glyoxal from all process 
lines; and
     Monthly production quantities of glyoxylic acid from all 
process lines.
    We are revising the final rule to clarify that these monthly 
production quantities must be supplied in metric tons and for each 
process line. Additionally, we are adding a requirement that facilities 
maintain records of the destruction efficiency of the N2O 
abatement technology from each process line, consistent with 
requirements of equation 2 to 40 CFR 98.513(e). Facilities will enter 
this information into EPA's electronic verification software in order 
to ensure proper verification of the reported emission values. 
Following electronic verification, facilities will be required to 
retain a record of the file generated by the verification software 
specified in 40 CFR 98.5(b), therefore, no additional burden is 
anticipated.
2. Summary of Comments and Responses on Subpart YY
    The EPA previously requested comment on the addition of a 
caprolactam, glyoxal, and glyoxylic acid production source category as 
a new subpart to part 98 in the 2022 Data Quality Improvements 
Proposal. The EPA received no comments regarding the addition of the 
proposed source category. Subsequently, the EPA proposed to add new 
subpart YY for caprolactam, glyoxal, and glyoxylic acid production (see 
section IV.D. of the preamble to the 2023 Supplemental Proposal). The 
EPA received no comments regarding proposed subpart YY following the 
2023 Supplemental Proposal.

EE. Subpart ZZ--Ceramics Manufacturing

    We are finalizing the addition of subpart ZZ of part 98 (Ceramics 
Manufacturing) with revisions in some cases. Section III.EE.1. of this 
preamble discusses the final requirements of subpart ZZ. The EPA 
received a number of comments on the proposed subpart ZZ which are 
discussed in section III.EE.2. of this preamble. We are also finalizing 
as proposed related confidentiality determinations for data elements 
resulting from the addition of subpart ZZ as described in section VI. 
of this preamble.
1. Summary of Final Amendments to Subpart ZZ
    This section summarizes the final amendments to subpart ZZ. Major 
changes to the final rule as compared to the proposed revisions are 
identified in this section. The rationale for these and any other 
changes to 40 CFR part 98, subpart ZZ can be found in section III.EE.2. 
of this preamble. Additional rationale for these amendments is 
available in the preamble to the 2022 Data Quality Improvements 
Proposal and 2023 Supplemental Proposal.
a. Source Category Definition
    In the 2023 Supplemental Proposal, the EPA defined the ceramics 
manufacturing source category as any facility that uses nonmetallic, 
inorganic materials, many of which are clay-based, to produce ceramic 
products such as bricks and roof tiles, wall and floor tiles, table and 
ornamental ware (household ceramics), sanitary ware, refractory 
products, vitrified clay pipes, expanded clay products, inorganic 
bonded abrasives, and technical ceramics (e.g., aerospace, automotive, 
electronic, or biomedical applications).
    The EPA also proposed that the ceramics source category would apply 
to facilities that annually consume at least 2,000 tons of carbonates 
or 20,000 tons of clay heated to a temperature sufficient to allow the 
calcination reaction to occur, and operate a ceramics manufacturing 
process unit. The proposed definition of ceramics manufacturers as 
facilities that use at least the minimum quantity of carbonates or clay 
(2,000 tons/20,000 tons) was considered consistent with subpart U of 
part 98 (Miscellaneous Uses of Carbonate). This minimum 2,000 tons of 
carbonate use was added to subpart U in the 2009 Final Rule based on 
comments received on the April 10, 2009 proposed rule (74 FR 16448), 
where commenters requested a carbonate use threshold of 2,000 tons in 
order to exempt small operations and activities which use carbonates in 
trace quantities. The proposed source category definition for ceramics 
manufacturing in the 2023 Supplemental Proposal established a minimum 
production level as a means to exclude and thus reduce the reporting 
burden for small artisan-level ceramics manufacturing processes. We 
defined a ceramics manufacturing process unit as a kiln, dryer, or oven 
used to calcine clay or other carbonate-based materials for the 
production of a ceramics product.
    The EPA is finalizing the definition of the source category with 
one change. We are revising the minimum production level in the 
definition from ``at least 2,000 tons of carbonates or 20,000 tons of 
clay which is heated to a temperature sufficient to allow the 
calcination reaction to occur'' to ``at least 2,000 tons of carbonates, 
either as raw materials or as a constituent in clay, which is heated to 
a temperature sufficient to allow the calcination reaction to occur.'' 
These final revisions focus the production level on the carbonates 
contained within the raw material rather than the total tons of clay; 
the final revisions will provide a more accurate means of assessing 
applicability. Facilities will be required to estimate their carbonate 
usage using available records to determine applicability. For example, 
facilities that use clay as a raw material input could calculate 
whether they meet the carbonate use threshold by multiplying the amount 
of clay they consume (and heat to calcination) annually by the weight 
fraction of carbonates contained in the clay. These final revisions add 
two harmonizing edits to 40 CFR 98.523(b)(1) and 98.526(c)(2) to 
clarify that the carbonate-based raw materials include clay.
b. Reporting Threshold
    In the 2023 Supplemental Proposal, the EPA proposed that facilities 
must report under subpart ZZ if they met the definition of the source 
category and if their estimated combined emissions (including from 
stationary combustion and all applicable source categories) exceed a 
25,000 mtCO2e threshold. We are finalizing the threshold as 
proposed. The final definition of ceramics manufacturers as facilities 
that use at least the minimum quantity of carbonates (2,000 tons, 
either as raw materials or as a constituent in clay) and

[[Page 31873]]

the 25,000 mtCO2e threshold are both expected to ensure that 
small ceramics manufacturers are excluded. It is estimated that over 25 
facilities will meet the definition of a ceramics manufacturer and the 
threshold of 25,000 mtCO2e for reporting. For a full 
discussion of this analysis, section IV.E. of the preamble to the 2023 
Supplemental Proposal.
c. Calculation Methods
    In the 2023 Supplemental Proposal, the EPA reviewed the production 
processes and available emissions estimation methods for ceramics 
manufacturing and proposed that only CO2 emissions would be 
estimated from these processes. The EPA also proposed to require the 
reporting of combustion emissions, including CO2, 
CH4, and N2O from the ceramics manufacturing unit 
and other combustion sources on site.
    In the 2023 Supplemental Proposal, the EPA reviewed the production 
processes and available emissions estimation methods for ceramics 
manufacturing including a basic mass balance methodology that assumed a 
fixed percentage for carbonates consumed (IPCC Tier 1), a carbon 
balance methodology (IPCC Tier 3) based on carbon content and the mass 
of materials input, and direct measurement using CEMS (see section 
IV.C.5. of the preamble to the 2023 Supplemental Proposal). We are 
finalizing, as proposed, two different methods for quantifying GHG 
emissions from ceramics manufacturing, depending on current emissions 
monitoring at the facility. If a qualified CEMS is in place, the CEMS 
must be used. Otherwise, the facility can elect to either install a 
CEMS or elect to use the carbon mass balance method.
    Direct measurement using CEMS. Facilities with a CEMS that meet the 
requirements in subpart C of part 98 (General Stationary Fuel 
Combustion) will be required to use CEMS to estimate the combined 
process and combustion CO2 emissions. The CEMS measures 
CO2 concentration and total exhaust gas flow rate for the 
combined process and combustion source emissions. CO2 mass 
emissions will be calculated from these measured values using equation 
C-6 and, if necessary, equation C-7 in 40 CFR 98.33(a)(4). The combined 
process and combustion CO2 emissions will be calculated 
according to the Tier 4 Calculation Methodology specified in 40 CFR 
98.33(a)(4). Facilities will be required to use subpart C to estimate 
emissions of CO2, CH4, and N2O from 
stationary combustion.
    Carbon balance method. For facilities using carbon mass balance 
method, the carbon content and the mass of carbonaceous materials input 
to the process must be determined. The facility must measure the 
consumption of specific process inputs and the amounts of these 
materials consumed by end-use/product type. Carbon contents of 
materials must be determined through the analysis of samples of the 
material or from information provided by the material suppliers. 
Additionally, the quantities of materials consumed and produced during 
production must be measured and recorded. CO2 emissions are 
estimated by multiplying the carbon content of each raw material by the 
corresponding mass, by a carbonate emission factor, and by the decimal 
fraction of calcination achieved for that raw material. We are 
finalizing the carbonate emission factors provided in table 1 to 
subpart ZZ of part 98 as proposed. These factors, pulled from table N-1 
to subpart N of part 98, and from Table 2.1 of the 2006 IPCC 
Guidelines,\44\ are based on stoichiometric ratios and represent the 
weighted average of the emission factors for each particular carbonate. 
Emission factors provided by the carbonate vendor for other minerals 
not listed in table 1 to subpart ZZ may also be used.
---------------------------------------------------------------------------

    \44\ IPCC Guidelines for National Greenhouse Gas Inventories, 
Volume 3, Industrial Processes and Product Use, Mineral Industry 
Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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    For any stationary combustion units included at the facility, 
facilities will be required to follow subpart C to estimate emissions 
of CO2, CH4, and N2O from stationary 
combustion. Use of facility specific information under the carbon mass 
balance method is consistent with IPCC Tier 3 methods and is the 
preferred method for estimating emissions for other GHGRP sectors.
d. Monitoring, QA/QC, and Verification Requirements
    The EPA is finalizing, as proposed, two separate monitoring 
methods: direct measurement and a mass balance emission calculation.
    Direct measurement using CEMS. We are finalizing the CEMS 
monitoring requirements as proposed. In the case of ceramics 
manufacturing, process and combustion GHG emissions from ceramics 
process units are typically emitted from the same stack. If facilities 
use an existing CEMS to meet the monitoring requirements, they will be 
required to use CEMS to estimate CO2 emissions. Where the 
CEMS capture all combustion- and process-related CO2 
emissions, facilities will be required to follow the requirements of 
subpart C of part 98 to estimate all CO2 emissions from the 
industrial source. The CEMS method requires both a continuous 
CO2 concentration monitor and a continuous volumetric flow 
monitor. To qualify as a CEMS, the monitors will be required to be 
installed, operated, and calibrated according to subpart C of part 98 
(40 CFR 98.33(a)(4)), which is consistent with CEMS requirements in 
other GHGRP subparts.
    Carbon balance method. We are finalizing the carbon mass balance 
method as proposed, with one change. The carbon mass balance method 
requires monitoring of mass quantities of carbonate-based raw material 
(e.g., clay) fed to the process, establishing the mass fraction of 
carbonate-based minerals in the raw material, and an emission factor 
based on the type of carbonate consumed. The mass quantities of 
carbonate-based raw materials consumed by each ceramics process unit 
can be determined using direct weight measurement of plant instruments 
or techniques used for accounting purposes, such as calibrated scales, 
weigh hoppers, or weigh belt feeders. The direct weight measurement can 
then be compared to records of raw material purchases for the year.
    For the carbon content of the materials used to calculate process 
CO2 emissions, the final rule requires that the owner or 
operator determine the carbon mass fraction either by using information 
provided by the raw material supplier, by collecting and sending 
representative samples of each carbonate-based material consumed to an 
off-site laboratory for a chemical analysis of the carbonate content 
(weight fraction), or by choosing to use the default value of 1.0. The 
use of 1.0 for the mass fraction assumes that the carbonate-based raw 
material comprises 100 percent of one carbonate-based mineral. We are 
revising the final rule to also state that where it is determined that 
the mass fraction of a carbonate-based raw material is below the 
detection limit of available testing standards, the facility must 
assume a default of 0.005 for that material.
    We are revising the final rule to allow facilities that determine 
the carbonate-based mineral mass fractions of a carbonate-based 
material to use additional sampling and chemical analysis methods to 
provide additional flexibility for facilities. Specifically, we are 
revising 40 CFR 98.524(b) from requiring sampling and chemical analysis 
using consensus standards that specify x-ray fluorescence to requiring 
that facilities use an ``x-ray fluorescence test, x-ray diffraction 
test, or other enhanced testing method published by an industry 
consensus standards

[[Page 31874]]

organization'' (e.g., ASTM, American Society of Mechanical Engineers 
(ASME), American Petroleum Institute (API)). The final rule requires 
the carbon content be analyzed at least annually to verify the mass 
fraction data provided by the supplier of the raw material.
    For the ceramics manufacturing source category, we are finalizing 
the QA/QC requirements as proposed. Reporters must calibrate all meters 
or monitors and maintain documentation of this calibration as 
documented in subpart A of part 98 (General Provisions). These meters 
or monitors should be calibrated prior to the first reporting year, 
using a suitable method published by a consensus standards 
organization, and will be required to be recalibrated either annually 
or at the minimum frequency specified by the manufacturer. In addition, 
any flow rate monitors used for direct measurement will be required to 
comply with QA/QC procedures for daily calibration drift checks and 
quarterly or annual accuracy assessments, such as those provided in 
Appendix F to part 60 or similar QA/QC procedures. We are finalizing 
these requirements to ensure the quality of the reported GHG emissions 
and to be consistent with the current requirements for CEMS 
measurements within subparts A (General Provisions) and C of the GHGRP. 
For measurements of carbonate content, reporters will assess 
representativeness of the carbonate content received from suppliers 
with laboratory analysis.
e. Procedures for Estimating Missing Data
    We are finalizing the procedures for estimation of missing data as 
proposed. The final rule requires the use of substitute data whenever a 
quality-assured value of a parameter that is used to calculate 
emissions is unavailable, or ``missing.'' For example, if the CEMS 
malfunctions during unit operation, the substitute data value would be 
the average of the quality-assured values of the parameter immediately 
before and immediately after the missing data period. For missing data 
on the amounts of carbonate-based raw materials consumed, we are 
finalizing that reporters must use the best available estimate based on 
all available process data or data used for accounting purposes, such 
as purchase records. For missing data on the mass fractions of 
carbonate-based minerals in the carbonate-based raw materials, 
reporters will assume that the mass fraction of each carbonate-based 
mineral is 1.0. The use of 1.0 for the mass fraction assumes that the 
carbonate-based raw material comprises 100 percent of one carbonate-
based mineral. Missing data procedures will be applicable for CEMS 
measurements, mass measurements of raw material, and carbon content 
measurements.
f. Data Reporting Requirements
    The EPA is finalizing the data reporting requirements for subpart 
ZZ as proposed, with one minor revision. Each ceramics manufacturing 
facility must report the annual CO2 process emissions from 
each ceramics manufacturing process, as well as any stationary fuel 
combustion emissions. In addition, facilities must report additional 
information that forms the basis of the emissions estimates so that we 
can understand and verify the reported emissions. For ceramic 
manufacturers, the additional information will include: the total 
number of ceramics process units at the facility and the total number 
of units operating; annual production of each ceramics product for each 
process unit and for all ceramics process units combined; the annual 
production capacity of each ceramics process unit; and the annual 
quantity of carbonate-based raw material charged to each ceramics 
process unit and for all ceramics process units combined. The EPA has 
revised the final rule to clarify at 40 CFR 98.526(c) that facilities 
that use the carbon balance method must also report the annual quantity 
of each carbonate-based raw material (including clay) charged to each 
ceramics process unit. This change is consistent with the requirements 
the EPA proposed for facilities conducting direct measurement using 
CEMS, and is not anticipated to substantively impact the burden to 
reporters as proposed. For ceramic manufacturers with non-CEMS units, 
the finalized rules will also require reporting of the following 
information: the method used for the determination for each carbon-
based mineral in each raw material; applicable test results used to 
verify the carbonate based mineral mass fraction for each carbonate-
based raw material charged to a ceramics process unit, including the 
date of test and test methods used; and the number of times in the 
reporting year that missing data procedures were used.
g. Records That Must Be Retained
    The EPA is finalizing the record retention requirements of subpart 
ZZ as proposed. All facilities are required to maintain monthly records 
of the ceramics manufacturing rate for each ceramics process unit and 
the monthly amount of each carbonate-based raw material charged to each 
ceramics process unit.
    For facilities that use the carbon balance procedure, the final 
rule requires facilities to also maintain monthly records of the 
carbonate-based mineral mass fraction for each mineral in each 
carbonate-based raw material. Additionally, facilities that use the 
carbon balance procedure will be required to maintain (1) records of 
the supplier-provided mineral mass fractions for all raw materials 
consumed annually; (2) results of all analyses used to verify the 
mineral mass fraction for each raw material (including the mass 
fraction of each sample, the date of test, test methods and method 
variations, equipment calibration data, and identifying information for 
the laboratory conducting the test); and (3) annual operating hours for 
each unit. If facilities use the CEMS procedure, they are required to 
maintain the CEMS measurement records.
    Procedures for ensuring accuracy of measurement methods, including 
calibration, must be recorded. The final rule requires records of how 
measurements are made, including measurements of quantities of 
materials used or produced and the carbon content of minerals in raw 
materials.
    Finally, the final rule requires the retention of a record of the 
file generated by the verification software specified in 40 CFR 98.5(b) 
including:
     Annual average decimal mass fraction of each carbonate-
based mineral per carbonate-based raw material for each ceramics 
process unit (percent by weight expressed as a decimal fraction);
     Annual mass of each carbonate-based raw material charged 
to each ceramics process unit (tons); and
     The decimal fraction of calcination achieved for each 
carbonate-based raw material for each ceramics process unit (percent by 
weight expressed as a decimal fraction).
2. Summary of Comments and Responses on Subpart ZZ
    This section summarizes the major comments and responses related to 
the proposed subpart ZZ. The EPA previously requested comment on the 
addition of ceramics manufacturing sources category as a new subpart to 
part 98 in the 2022 Data Quality Improvements Proposal. The EPA 
received some comments for subpart ZZ on the 2022 Data Quality 
Improvements Proposal; the majority of these comments were previously 
addressed in the preamble to the 2023 Supplemental Proposal, wherein 
the EPA proposed to add new subpart ZZ for ceramics manufacturing (see 
section III.E. of the

[[Page 31875]]

preamble to the 2023 Supplemental Proposal). The EPA received 
additional comments regarding the proposed subpart ZZ following the 
2023 Supplemental Proposal. See the document ``Summary of Public 
Comments and Responses for 2024 Final Revisions and Confidentiality 
Determinations for Data Elements under the Greenhouse Gas Reporting 
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of 
all comments and responses related to subpart ZZ.
    Comments: One commenter objected to the EPA's inclusion of the 
brick manufacturing industry in proposed subpart ZZ. The commenter 
asserted that GHG emissions from the brick industry represent only 
about 0.027 percent of U.S. anthropogenic emissions, stating that any 
relative improvement in accuracy of emissions would not change the fact 
that GHG emissions from brick manufacturing are a very small fraction 
of the national total.
    The commenter provided a number of reasons to exclude brick 
manufacturing from subpart ZZ. First, the commenter contested the EPA's 
assumption that all ceramics manufacturing use materials with 
significant carbonate content. The commenter stated that the materials 
used for the production of brick are low carbonate clay and shale 
materials that should not be characterized as ``carbonate-based 
materials,'' and that the various processes used to prepare raw 
materials and to form and fire brick are such that higher carbonate 
materials cannot be used. The commenter added that high carbonate 
materials can result in durability problems of the brick, ranging from 
cosmetic ``lime pops'' to scenarios where the brick can actually fail 
in service. The commenter further stated that the majority production 
of brick in the United States is red bodied brick, and therefore the 
use of carbonates including limestone are undesirable, due to bleaching 
of the red color during firing.
    The commenter explained that the EPA's proposal assumes a carbonate 
content of 10-15 percent, whereas tested averages for brick making 
materials average 0.58 percent. The commenter provided a table of 
carbonate brick values based on testing from the NBRC (National Brick 
Research Center at Clemson University). The commenter stated that, as 
such, the actual brick making carbonate percentages are only about 3.8-
5.8 percent (0.58 percent divided by 10 percent and 15 percent, 
respectively) of the carbonate material percentages in the proposed 
rule. The commenter estimated that based on this determination, the 
inclusion of carbonate process emissions would only increase reported 
emissions from a facility by about 2.10 percent, and few, if any, 
additional sites not already reporting exceeding the 25,000 
mtCO2e reporting threshold would be required to report. The 
commenter added that even if facilities do not meet the threshold, the 
added requirements would impose on all sites additional testing and 
measurement requirements to determine if they exceed the reporting 
threshold. The commenter stated that the associated costs do not 
justify the requirements.
    The commenter stated that a limited number of brickmaking sites add 
small amounts of carbonates to some of their products for various 
reasons. The commenter explained that some manufacturers add barium 
carbonate to the brick body mix to prevent soluble salts from forming 
on the final product. In such cases, the commenter noted that barium 
carbonate is added typically in the range of 0.05 to 0.1 percent. The 
commenter also stated that sodium carbonate (added in the range of 0.5 
percent) is sometimes used to improve the uptake of water during the 
brick forming process. The commenter asserted that in such cases, if 
the additional usages of carbonates are significant, they already would 
be reported under subpart U.
    The commenter noted that the EPA's existing methods for estimating 
GHG emissions from the brick manufacturing industry are good enough to 
adequately inform the Agency's policy/regulatory decision making and to 
satisfy the EPA's desire and obligation to maintain an accurate 
national GHG emissions inventory. The commenter suggested that the EPA 
could, in lieu of annual reporting, issue a one-time information 
collection request.
    Response: The EPA has considered the information provided by the 
commenter and is finalizing the addition of the ceramics category to 
include the brick industry. Consistent with the other source categories 
of 40 CFR part 98, requiring annual reporting of data for ceramics 
facilities is preferred to a one-time information collection request. 
The collection of annual data will help the EPA to understand changes 
in industry emissions and trends over time. The snapshot of information 
provided by a one-time information collection request would not provide 
the type of ongoing information which could inform potential 
legislation or EPA policy. Collecting annual data also allows us to 
incorporate accurate time-series emissions changes for the ceramics 
industry in the GHG Inventory and other EPA analyses. Further, 
including brick manufacturing in the ceramics source category is 
consistent with the 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories.\45\ While the commenter asserts that brick manufacturing 
is a small percentage of the total national GHG emissions, the ceramics 
subpart would cover more industries than just brick manufacturing and 
is anticipated to cover emissions comparable to other existing 
subparts. We have included both an emissions threshold and a carbonate 
use threshold in order to exempt small facilities or those with minor 
emissions.
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    \45\ IPCC Guidelines for National Greenhouse Gas Inventories, 
Volume 3, Industrial Processes and Product Use, Mineral Industry 
Emissions. 2006. Prepared by the National Greenhouse Gas Inventories 
Programme, Eggleston H.S., Buendia L., Miwa K., Ngara T. and Tanabe 
K. (eds). Published: IGES, Japan. www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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    Rather than exempting the brick industry from the ceramics subpart 
entirely, we have taken the commenter's concerns into account and are 
modifying the definition of the source category such that the subpart 
``would apply to facilities that annually consume at least 2,000 tons 
of carbonates, either as raw materials or as a constituent in clay . . 
.''. This is in contrast to the original proposed definition which 
included the phrase ``or 20,000 tons of clay.'' This revised carbonate 
use threshold will exclude and thus avoid the reporting burden for 
facilities that use low annual quantities of carbonates, such as brick 
manufacturers that use low-carbonate clay. Facilities could estimate 
their carbonate usage to determine their applicability for whether they 
meet this carbonate use threshold by multiplying the annual amount of 
clay consumed as a raw material (and heated to calcination) by the 
weight fraction of carbonates contained in the clay.
    Comment: One commenter objected to the proposed measurement 
protocols of subpart ZZ and indicated that the methods are infeasible 
for brick manufacturing materials. The commenter stated that the 
proposal cites ``suitable chemical analysis methods include using an x-
ray fluorescence standard method.'' The commenter asserted that the use 
of x-ray fluorescence requires a minimum of at least 2.0 percent of any 
single carbonate material to speciate and determine an amount, which is 
higher than the total of all carbonates in brick making material, which 
the commenter

[[Page 31876]]

provided as 0.58 percent based on testing.
    The commenter stated that for brick manufacturing, an alternate 
measurement of total carbonates such as ASTM E1915 Standard Test 
Methods for Analysis of Metal Bearing Ores and Related Materials for 
Carbon, Sulfur, and Acid-Base Characteristics (2020) \46\ and 
CO2e calculation would be a necessary option. The commenter 
suggested a simpler option would be to develop a default percentage of 
carbonate in brickmaking raw materials, or an AP-42, Compilation of Air 
Pollutant Emissions Factors type metric allowing a direct calculation 
of CO2e emissions per product throughput tonnage. The 
commenter contended that this would still yield sufficiently accurate 
results and suggested that the historical testing data could be the 
basis for this option.
---------------------------------------------------------------------------

    \46\ Available at https://www.astm.org/e1915-20.html. Accessed 
January 9, 2024.
---------------------------------------------------------------------------

    Response: Upon careful review and consideration, the EPA has 
considered the information provided by the commenter and will finalize 
40 CFR 98.524(b) to allow for other industry standards (i.e., x-ray 
fluorescence test, x-ray diffraction test, or other enhanced testing 
method published by an industry consensus standards organization (e.g., 
ASTM, ASME, API)) as described in 40 CFR 98.524(d) to allow for the 
flexibility of using the most appropriate standard test method. 
Furthermore, following consideration of the commenter's recommendation 
that the EPA include a default carbonate percentage, we are revising 40 
CFR 98.524(b) to include a default value of 0.005 for each carbonate 
material where it is determined that the mass fraction is below the 
detection limit of available testing standards. The 0.005 value (0.5 
percent) is consistent with the example limestone mass fraction that 
was provided by the Brick Industry Association.\47\ Furthermore, the 
EPA's research into carbonate testing standards revealed that 0.01 (1 
percent) is an example detection limit for existing standards (e.g., 
ASTM F3419-22, Standard Test Method for Mineral Characterization of 
Equine Surface Materials by X-Ray Diffraction (XRD) Techniques (2022) 
\48\). In scientific settings, it is a common practice to assume that a 
value of one half the detection limit when concentrations are too low 
to accurately measure.
---------------------------------------------------------------------------

    \47\ See Docket ID. No. EPA-HQ-OAR-2019-0424-0332 at 
www.regulations.gov.
    \48\ Available at https://www.astm.org/f3419-22.html. Accessed 
January 9, 2024.
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    Comment: One commenter stated that the proposed rule requirements 
to report on a unit-by-unit basis instead of facility wide reporting 
would impose unnecessary burdens on the brick industry. The commenter 
asserted that most activities (natural gas billing, clay hauling 
deliveries, material preparation logs, etc.) are done on a per-site 
basis. The commenter added that there is no benefit to requiring 
reporting to be done on a per unit basis, and a per site basis should 
be adequate for determining if emissions exceed the 25,000 metric ton 
CO2e reporting threshold.
    Response: The EPA routinely collects unit-level capacity data for 
process equipment in 40 CFR part 98. These unit-level data are 
essential for quantifying actual GHG emissions from the facility (e.g., 
the carbon balance method for estimating emissions relies on the actual 
quantities of carbonate-based raw materials charged to the ceramics 
process units, not just those delivered to the facility). Furthermore, 
we use these data to perform statistical analyses as part of our 
verification process, which allows us to develop ranges of expected 
emissions by emission source type and successfully identify outliers in 
the reported data. We disagree that there will be no benefit to 
reporting on a unit-level basis, as this information will improve the 
EPA's verification of reported emissions and will provide a more 
accurate facility-level and national-level emissions profile for the 
industry.

IV. Final Revisions to 40 CFR Part 9

    The EPA is finalizing the proposed amendment to 40 CFR part 9 to 
include the OMB control number issued under the PRA for the ICR for the 
GHGRP. The EPA is amending the table in 40 CFR part 9 to list the OMB 
approval number (OMB No. 2060-0629) under which the ICR for activities 
in the existing part 98 regulations that were previously approved by 
OMB have been consolidated. The EPA received no comments on the 
proposed amendments to 40 CFR part 9 and is finalizing the change as 
proposed. This codification in the CFR satisfies the display 
requirements of the PRA and OMB's implementing regulations at 5 CFR 
part 1320.

V. Effective Date of the Final Amendments

    As proposed in the 2023 Supplemental Proposal, the final amendments 
will become effective on January 1, 2025. As provided under the 
existing regulations at 40 CFR 98.3(k), the GWP amendments to table A-1 
to subpart A will apply to reports submitted by current reporters that 
are submitted in calendar year 2025 and subsequent years (i.e., 
starting with reports submitted for RY2024 on or before March 31, 
2025). The revisions to GWPs do not affect the data collection, 
monitoring, or calculation methodologies used by these existing 
reporters. All other final revisions, which apply to both existing and 
new reporters, will be implemented for reports prepared for RY2025 and 
submitted March 31, 2026. Reporters who are newly subject to the rule 
(facilities that have not previously reported to the GHGRP), either due 
to final revisions that change what facilities must report under the 
rule (e.g., newly subject to subparts I or P or subparts WW, XX, YY, or 
ZZ), or due to the revisions to GWPs in table A-1 to subpart A, will be 
required to implement all requirements to collect data, including any 
required monitoring and recordkeeping, on January 1, 2025.
    This final rule includes new and revised requirements for numerous 
provisions under various aspects of GHGRP, including revisions to 
applicability and updates to reporting, recordkeeping, and monitoring 
requirements. Further, as explained in section I.B. and this section of 
this preamble, it amends numerous sections of part 98 for various 
specific reasons. Therefore, this final rule is a multifaceted rule 
that addresses many separate things for independent reasons, as 
detailed in each respective section of this preamble. We intended each 
portion of this rule to be severable from each other, though we took 
the approach of including all the parts in one rulemaking rather than 
promulgating multiple rules to amend each part of the GHGRP. For 
example, the following portions of this rulemaking are mutually 
severable from each other, as numbered: (1) revisions to General 
Provisions, including updates to GWPs in table A-1 to subpart A of part 
98 in section III.A.1. of this preamble, (2) revisions to applicability 
to subparts G (Ammonia Manufacturing), P (Hydrogen Production), and Y 
(Petroleum Refineries) to address non-merchant hydrogen production in 
sections III.E., III.I., and III.M.; (3) revisions to applicability to 
subparts Y and WW (Coke Calciners) to address stand-alone coke 
calcining operations; (4) revisions to subparts PP (Carbon Dioxide 
Suppliers) and new subpart VV (Geologic Sequestration of Carbon Dioxide 
with Enhanced Oil Recovery Using ISO 27916) in sections III.V. and 
III.Z.; (5) revisions to applicability in subparts UU (Injection of 
Carbon Dioxide) and subpart VV in sections

[[Page 31877]]

III.Z. and III.AA., (6) other regulatory amendments discussed in 
section III. and IV. of this preamble, and (7) confidentiality 
determinations as discussed in section VI. of this preamble. Each of 
the regulatory amendments in section III. is severable from all the 
other regulatory amendments in that section, and each of the 
confidentiality determinations in section VI. is also severable from 
all the other determinations in that section. If any of the above 
portions is set aside by a reviewing court, then we intend the 
remainder of this action to remain effective, and the remaining 
portions will be able to function absent any of the identified portions 
that have been set aside. Moreover, this list is not intended to be 
exhaustive, and should not be viewed as an intention by the EPA to 
consider other parts of the rule not explicitly listed here as not 
severable from other parts of the rule.

VI. Final Confidentiality Determinations

    This section provides a summary of the EPA's final confidentiality 
determinations and emission data designations for new and substantially 
revised data elements included in these final amendments, certain 
existing part 98 data elements for which no determination has been 
previously established, certain existing part 98 data elements for 
which the EPA is amending or clarifying the existing confidentiality 
determination, and the EPA's final reporting determinations for inputs 
to equations included in the final amendments. This section also 
summarizes the major comments and responses related to the proposed 
confidentiality determinations, emission data designations, and 
reporting determinations for these data elements.
    The EPA is not taking final action on any requirements for subpart 
W (Petroleum and Natural Gas Systems) in this final rule, therefore, we 
are not taking any action on confidentiality determinations or 
reporting determinations proposed for data elements in subpart W of 
part 98 in the 2022 Data Quality Improvements Proposal. See section 
I.C. of this preamble for a discussion of the EPA's actions regarding 
subpart W. Additionally, we are not taking any final action on proposed 
subpart B (Energy Consumption) in this final rule; therefore we are not 
taking any action on confidentiality determinations proposed in the 
2023 Supplemental Proposal for subpart B. See section III.B. of this 
preamble for additional information on subpart B.
    For all remaining data elements included in the 2022 Data Quality 
Improvements Proposal or 2023 Supplemental Proposal, this section 
identifies any changes to the proposed confidentiality determinations, 
emissions data designations, or reporting determinations in the final 
rule.

A. EPA's Approach To Assess Data Elements

    In the 2022 Data Quality Improvements Proposal and the 2023 
Supplemental Proposal, the EPA proposed to assess data elements for 
eligibility of confidential treatment using a revised approach, in 
response to Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 
2356 (2019) (hereafter referred to as Argus Leader).\49\ The EPA 
proposed that the Argus Leader decision did not affect our approach to 
designating data elements as ``inputs to emission equations'' or our 
previous approach for designating new and revised reporting 
requirements as ``emission data.'' We proposed to continue identifying 
new and revised reporting elements that qualify as ``emission data'' 
(i.e., data necessary to determine the identity, amount, frequency, or 
concentration of the emission emitted by the reporting facilities) by 
evaluating the data for assignment to one of the four data categories 
designated by the 2011 Final CBI Rule (76 FR 30782, May 26, 2011) to 
meet the CAA definition of ``emission data'' in 40 CFR 2.301(a)(2)(i) 
(hereafter referred to as ``emission data categories''). Refer to 
section II.B. of the July 7, 2010 proposal (75 FR 39094) for 
descriptions of each of these data categories and the EPA's rationale 
for designating each data category as ``emission data.'' For data 
elements designated as ``inputs to emission equations,'' the EPA 
maintained the two subcategories, data elements entered into e-GGRT's 
Inputs Verification Tool (IVT) and those directly reported to the EPA. 
Refer to section VI.C. of the preamble of the 2022 Data Quality 
Improvements Proposal for further discussion of ``inputs to emission 
equations.''
---------------------------------------------------------------------------

    \49\ Available in the docket for this rulemaking (Docket ID. No. 
EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------

    In the 2022 Data Quality Improvements Proposal, for new or revised 
data elements that the EPA did not propose to designate as ``emission 
data'' or ``inputs to emission equations,'' the EPA proposed a revised 
approach for assessing data confidentiality. We proposed to assess each 
individual reporting element according to the new Argus Leader 
standard. So, we evaluated each data element individually to determine 
whether the information is customarily and actually treated as private 
by the reporter and proposed a confidentiality determination based on 
that evaluation.
    The EPA received several comments on its proposed approach in the 
2022 Data Quality Improvements Proposal and the 2023 Supplemental 
Proposal. The commenters' concerns and the EPA's responses thereto are 
provided in the document ``Summary of Public Comments and Responses for 
2024 Final Revisions and Confidentiality Determinations for Data 
Elements under the Greenhouse Gas Reporting Rule'' in Docket ID. No. 
EPA-HQ-OAR-2019-0424. Following consideration of the comments received, 
the EPA is not revising this approach and is continuing to assess data 
elements for confidentiality determinations as described in the 2022 
Data Quality Improvements Proposal and the 2023 Supplemental Proposal. 
We are also finalizing the specific confidentiality determinations and 
reporting determinations as described in section VI.B. and VI.C. of 
this preamble.

B. Final Confidentiality Determinations and Emissions Data Designations

1. Summary of Final Confidentiality Determinations
a. Final Confidentiality Determinations for New and Revised Data 
Elements
    The EPA is making final confidentiality determinations and emission 
data designations for new and substantially revised data elements 
included in these final amendments. Substantially revised data elements 
include those data elements where the EPA is, in this final action, 
substantially revising the data elements as compared to the existing 
requirements. Please refer to the preamble to the 2022 Data Quality 
Improvements Proposal or the 2023 Supplemental Proposal for additional 
information regarding the proposed confidentiality determinations for 
these data elements.
    For subparts A (General Provisions), C (General Stationary Fuel 
Combustion), F (Aluminum Production), G (Ammonia Manufacturing), H 
(Cement Production), P (Hydrogen Production), S (Lime Manufacturing), 
HH (Municipal Solid Waste Landfills), OO (Suppliers of Industrial 
Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated 
Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell 
Foams), the EPA is not finalizing the proposed confidentiality 
determinations for certain data elements because the

[[Page 31878]]

EPA is not taking final action on the requirements to report these data 
elements at this time (see section III. of this preamble for additional 
information). These data elements are listed in table 5 of the 
memorandum ``Confidentiality Determinations and Emission Data 
Designations for Data Elements in the 2024 Final Revisions to the 
Greenhouse Gas Reporting Rule,'' available in the docket to this 
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424.
    For subparts C (General Stationary Fuel Combustion) and PP 
(Suppliers of Carbon Dioxide), the EPA has revised its final 
confidentiality determinations or emissions data designations for 
certain data elements from proposal. For subpart PP, following 
consideration of public comments, the EPA has revised its final 
confidentiality determination for eight data elements that were 
proposed as ``Not Eligible'' to ``Eligible for Confidential 
Treatment.'' See section VI.B.2. of this preamble for a summary of the 
related comments and the EPA's response. For subpart C, we identified 
two revised data elements where the EPA had inadvertently proposed to 
place the revised version of the data elements into a different 
emissions data category than the existing version of the data elements 
(i.e., proposed moving the data elements from one category of emissions 
data into a different category of emissions data). The EPA has 
corrected the placement of these data elements from ``Facility and Unit 
Identifier Information'' to ``Emissions.'' Table 6 of this preamble 
lists the data elements where the EPA has revised its final 
confidentiality determinations or emissions data designations as 
compared to the 2022 Data Quality Improvements Proposal.

 Table 6--Data Elements for Which the EPA Is Revising the Final Confidentiality Determinations or Emission Data
                                                  Designations
----------------------------------------------------------------------------------------------------------------
             Subpart                        Citation in 40 CFR part 98              Data element description
----------------------------------------------------------------------------------------------------------------
C \1\............................  98.36(c)(1)(vi)............................  When reporting using aggregation
                                                                                 of units, if any of the
                                                                                 stationary fuel combustion
                                                                                 units burn biomass, the annual
                                                                                 CO2 emissions from combustion
                                                                                 of all biomass fuels combined
                                                                                 (metric tons).
C \1\............................  98.36(c)(3)(vi)............................  When reporting using the common
                                                                                 pipe configuration, if any of
                                                                                 the stationary fuel combustion
                                                                                 units burn biomass, the annual
                                                                                 CO2 emissions from combustion
                                                                                 of all biomass fuels combined
                                                                                 (metric tons).
PP \2\...........................  98.426(i)(1)...............................  If you capture a CO2 stream at a
                                                                                 facility with a direct air
                                                                                 capture (DAC) process unit and
                                                                                 electricity (excluding combined
                                                                                 heat and power (CHP)) is
                                                                                 provided to a dedicated meter
                                                                                 for the DAC process unit:
                                                                                 annual quantity of electricity
                                                                                 (generated on-site or off-site)
                                                                                 consumed for the DAC process
                                                                                 unit (MWh).
PP \2\...........................  98.426(i)(1)(i)(C).........................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and electricity (excluding
                                                                                 CHP) is provided to a dedicated
                                                                                 meter for the DAC process unit:
                                                                                 if the electricity is sourced
                                                                                 from a grid connection, the
                                                                                 name of the electric utility
                                                                                 company that supplied the
                                                                                 electricity as shown on the
                                                                                 last monthly bill issued by the
                                                                                 utility company during the
                                                                                 reporting period.
PP \2\...........................  98.426(i)(1)(i)(D).........................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and electricity (excluding
                                                                                 CHP) is provided to a dedicated
                                                                                 meter for the DAC process unit:
                                                                                 if the electricity is sourced
                                                                                 from a grid connection, the
                                                                                 name of the electric utility
                                                                                 company that delivered the
                                                                                 electricity.
PP \2\...........................  98.426(i)(1)(i)(E).........................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and electricity (excluding
                                                                                 CHP) is provided to a dedicated
                                                                                 meter for the DAC process unit:
                                                                                 if the electricity is sourced
                                                                                 from a grid connection, the
                                                                                 annual quantity of electricity
                                                                                 consumed for the DAC process
                                                                                 unit (MWh).
PP \2\...........................  98.426(i)(1)(ii)...........................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and electricity (excluding
                                                                                 CHP) is provided to a dedicated
                                                                                 meter for the DAC process unit:
                                                                                 if electricity is sourced from
                                                                                 on-site or through a
                                                                                 contractual mechanism for
                                                                                 dedicated off-site generation,
                                                                                 the annual quantity of
                                                                                 electricity consumed per
                                                                                 applicable source (MWh), if
                                                                                 known.
PP \2\...........................  98.426(i)(2)...............................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and you use heat, steam,
                                                                                 or other forms of thermal
                                                                                 energy (excluding CHP) for the
                                                                                 DAC process unit: the annual
                                                                                 quantity of heat, steam, or
                                                                                 other forms of thermal energy
                                                                                 sourced from on-site or through
                                                                                 a contractual mechanism for
                                                                                 dedicated off-site generation
                                                                                 per applicable energy source
                                                                                 (MJ), if known.
PP \2\...........................  98.426(i)(3)(i)............................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and electricity from CHP
                                                                                 is sourced from on-site or
                                                                                 through a contractual mechanism
                                                                                 for dedicated off-site
                                                                                 generation: the annual quantity
                                                                                 of electricity consumed for the
                                                                                 DAC process unit per applicable
                                                                                 energy source (MWh), if known.
PP \2\...........................  98.426(i)(3)(ii)...........................  If you capture a CO2 stream at a
                                                                                 facility with a DAC process
                                                                                 unit and you use heat from CHP
                                                                                 for the DAC process unit: the
                                                                                 annual quantity of heat, steam,
                                                                                 or other forms of thermal
                                                                                 energy from CHP sourced from on-
                                                                                 site or through a contractual
                                                                                 mechanism for dedicated off-
                                                                                 site generation per applicable
                                                                                 energy source (MJ), if known.
----------------------------------------------------------------------------------------------------------------
\1\ In the May 26, 2011, final rule (76 FR 30782), this data element was assigned to the ``Emissions Data'' data
  category and determined to be ``Emissions Data.'' In the 2022 Data Quality Improvements Proposal, the data
  element was significantly revised, and the EPA proposed that the revised data element would be assigned to the
  data category ``Facility and Unit Identifier'' and would have a determination of ``Emissions Data.'' We have
  subsequently determined that the revisions to the data element (revising the language ``if any units burn both
  fossil fuels and biomass'' with ``if any of the units burn biomass'') is a clarifying change and that the data
  element was incorrectly assigned to a new data category. Therefore we are finalizing the revised data element
  in the ``Emissions Data'' data category and determining that it is ``Emissions Data.''
\2\ Revised from ``Not Eligible'' to ``Eligible for Confidential Treatment''; see section VI.B.2. of this
  preamble.

    For subparts I (Electronics Manufacturing), P (Hydrogen 
Production), and ZZ (Ceramics Manufacturing), the EPA is finalizing 
revisions that include new data elements for which the EPA did not 
propose a determination. These data elements are listed in table 7 of 
this preamble and table 6 of the memorandum, ``Confidentiality 
Determinations and Emission Data Designations for Data Elements in the 
2024 Final Revisions to the Greenhouse Gas Reporting Rule,'' available 
in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. 
Because the EPA has not proposed or solicited public comment on a 
determination for

[[Page 31879]]

these data elements, we are not finalizing confidentiality 
determinations for these data elements at this time.

      Table 7--New Data Elements From Proposal to Final for Which the EPA Is Not Finalizing Confidentiality
                                  Determinations or Emission Data Designations
----------------------------------------------------------------------------------------------------------------
             Subpart                        Citation in 40 CFR part 98              Data element description
----------------------------------------------------------------------------------------------------------------
I................................  98.96(y)(2)(iv)............................  For electronics manufacturing
                                                                                 facilities, for the technology
                                                                                 assessment report required
                                                                                 under 40 CFR 98.96(y), for any
                                                                                 destruction or removal
                                                                                 efficiency data submitted, if
                                                                                 you choose to use an additional
                                                                                 alternative calculation
                                                                                 methodology to calculate and
                                                                                 report the input gas emission
                                                                                 factors and by-product
                                                                                 formation rates: a complete,
                                                                                 mathematical description of the
                                                                                 alternative method used
                                                                                 (including the equation used to
                                                                                 calculate each reported
                                                                                 utilization and by-product
                                                                                 formation rate).
P................................  98.166(d)(10)..............................  For each hydrogen production
                                                                                 process unit, an indication
                                                                                 (yes or no) if best available
                                                                                 monitoring methods used in
                                                                                 accordance with 40 CFR
                                                                                 98.164(c) to determine fuel
                                                                                 flow for each stationary
                                                                                 combustion unit directly
                                                                                 associated with hydrogen
                                                                                 production (e.g., reforming
                                                                                 furnace and hydrogen production
                                                                                 process unit heater).
P................................  98.166(d)(10)(i)...........................  For each hydrogen production
                                                                                 process unit, if best available
                                                                                 monitoring methods were used in
                                                                                 accordance with 40 CFR
                                                                                 98.164(c) to determine fuel
                                                                                 flow for each stationary
                                                                                 combustion unit directly
                                                                                 associated with hydrogen
                                                                                 production, the beginning date
                                                                                 of using best available
                                                                                 monitoring methods.
P................................  98.166(d)(10)(ii)..........................  For each hydrogen production
                                                                                 process unit, if best available
                                                                                 monitoring methods were used in
                                                                                 accordance with 40 CFR
                                                                                 98.164(c) to determine fuel
                                                                                 flow for each stationary
                                                                                 combustion unit directly
                                                                                 associated with hydrogen
                                                                                 production, the anticipated or
                                                                                 actual end date of using best
                                                                                 available monitoring methods.
ZZ...............................  98.526(c)(2)...............................  For a facility containing a
                                                                                 ceramics manufacturing process,
                                                                                 for each ceramics manufacturing
                                                                                 process unit, if process CO2
                                                                                 emissions are calculated
                                                                                 according to the procedures
                                                                                 specified in 40 CFR 98.523(b),
                                                                                 annual quantity of each
                                                                                 carbonate-based raw material
                                                                                 (including clay) charged (tons)
                                                                                 (no CEMS).
----------------------------------------------------------------------------------------------------------------

    In a handful of cases, the EPA has made minor revisions to data 
elements in this final action as compared to the proposed data element 
included in either the 2022 Data Quality Improvements Proposal or the 
2023 Supplemental Proposal. For certain proposed data elements, we have 
revised the citations from proposal to final. In other cases, the minor 
revisions include clarifications to the text. The EPA evaluated these 
data elements and how they have been clarified in the final rule to 
verify that the information collected has not substantially changed 
since proposal. These data elements are listed in table 7 of the 
memorandum ``Confidentiality Determinations and Emission Data 
Designations for Data Elements in the 2024 Final Revisions to the 
Greenhouse Gas Reporting Rule,'' available in the docket to this 
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. Because the 
information to be collected has not substantially changed since 
proposal, we are finalizing the confidentiality determinations or 
emission data designations for these data elements as proposed. For 
additional information on the rationales for the confidentiality 
determinations for these data elements, see the preamble to the 2022 
Data Quality Improvements Proposal or the 2023 Supplemental Proposal 
and the memoranda ``Proposed Confidentiality Determinations and 
Emission Data Designations for Data Elements in Proposed Revisions to 
the Greenhouse Gas Reporting Rule'' and ``Proposed Confidentiality 
Determinations and Emission Data Designations for Data Elements in 
Proposed Supplemental Revisions to the Greenhouse Gas Reporting Rule,'' 
available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-
2019-0424).
    For all other confidentiality determinations for the new or 
substantially revised data reporting elements for these subparts, the 
EPA is finalizing the confidentiality determinations as they were 
proposed. Please refer to the preamble to the 2022 Data Quality 
Improvements Proposal or the 2023 Supplemental Proposal for additional 
information regarding these confidentiality determinations.
b. Final Confidentiality Determinations and Emission Data Designations 
for Existing Data Elements for Which EPA Did Not Previously Finalize a 
Confidentiality Determination or Emission Data Designation
    The EPA is finalizing all confidentiality determinations as they 
were proposed for other part 98 data reporting elements for which no 
determination has been previously established. The EPA received no 
comments on the proposed determinations. Please refer to the preamble 
to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental 
Proposal for additional information regarding the proposed 
confidentiality determinations.
c. Final Confidentiality Determinations for Existing Data Elements for 
Which the EPA is Amending or Clarifying the Existing Confidentiality 
Determination
    The EPA is finalizing as proposed all confidentiality 
determinations for other part 98 data reporting elements for which the 
EPA proposed to amend or clarify the existing confidentiality 
determinations. The EPA received no comments on the proposed 
determinations. Please refer to the preamble to the 2022 Data Quality 
Improvements Proposal for additional information regarding the proposed 
confidentiality determinations.
2. Summary and Response to Public Comments on Proposed Confidentiality 
Determinations
    The EPA received several comments related to the proposed 
confidentiality determinations. The EPA received minimal comments on 
the proposed confidentiality determinations for all new or 
substantially revised data elements, except certain data elements in 
subparts PP (Suppliers of Carbon Dioxide) and VV (Geologic 
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 
27916) as described in this section. Additional comments may be found 
in the EPA's comment response document in Docket ID. No. EPA-HQ-OAR-
2019-

[[Page 31880]]

0424. For subparts PP and VV, we received comments questioning the 
proposed confidentiality determination of certain new and substantially 
revised data elements in each subpart, including requests that the data 
elements be treated as confidential. Summaries of the major comments 
and the EPA's responses thereto are provided below. Additional comments 
and the EPA's responses may be found in the comment response document 
noted above.
    Comment: One commenter contended that public disclosure of the 
annual quantity of electricity consumed to power the DAC process unit 
and natural gas used for thermal energy could undermine the commercial 
deployment of DAC. The commenter stated that this information should be 
kept as confidential. The commenter explained that power in a DAC 
facility is one of the main operating expenses and power consumption is 
directly related to power cost. The commenter stated that a 
comprehensive understanding of a DAC unit's power demand, coupled with 
a basic understanding of the clean power markets in the region where 
the DAC facility is located, could be used to estimate the DAC power 
cost. The commenter contended that this knowledge, if available to a 
competitor or provider of clean power, would affect business-to-
business contract negotiations, allow for speculation on potential 
profit margins on captured CO2 volumes, and negatively 
impact the ability of a DAC operator to procure clean power at 
competitive rates.
    The commenter added that many carbon capture technologies will 
utilize natural gas to provide the thermal energy needed to drive the 
CO2 capture process, including DAC facilities. The commenter 
explained contract negotiations for the supply of natural gas for DAC 
facilities are competitive and a major operating cost for a DAC 
facility and information on the annual amount of natural gas consumed 
by a DAC facility, if available to a competitor or natural gas 
supplier, will affect the ability of a DAC operator to contract for 
responsibly sourced natural gas supply at a competitive cost. The 
commenter requested that natural gas consumption be declared CBI. The 
commenter added that they still supported the requirement to report on 
whether flue gas is also captured by the DAC process unit as this 
requirement allows for a clear distinction of CO2 captured 
from the process versus CO2 captured from the air, 
increasing public trust in reported CO2 volumes.
    Response: The EPA proposed that 12 new subpart PP data elements in 
40 CFR 98.426(i) specific to DAC facilities would not be eligible for 
confidential treatment. These data elements included: the annual 
quantities of on-site and off-site electricity consumed for the DAC 
process unit; the annual quantities of heat, steam, other forms of 
thermal energy, and combined heat and power (CHP) consumed by the DAC 
process unit; the state and county where the facility with the DAC 
process unit is located; the name of the electric utility company that 
supplied and delivered the electricity if electricity is sourced from a 
grid connection; the annual quantity of electricity consumed by the DAC 
process unit supported by billing statements; the annual quantity of 
electricity, heat, and CHP consumed for the DAC process unit by each 
applicable source; and whether flue gas is also captured by the DAC 
process unit when electricity or CHP is generated on-site from natural 
gas, coal, or oil.
    The EPA's proposed determinations were based on research that 
indicated the proposed data elements are not customarily and actually 
treated as private by the reporter. We note that this, rather than 
competitive harm, is now the standard for treating reported data 
elements as ``Eligible for Confidential Treatment'' or ``Not Eligible'' 
based on the decision in Food Marketing Institute v. Argus Leader 
Media, 139 S. Ct. 2356 (2019). While the commenter explains that there 
may be competitive harm from releasing electricity and natural gas 
consumption data in 40 CFR 98.426, they do not clearly demonstrate 
whether such data are customarily and actually treated as confidential. 
Following receipt of public comment, the EPA conducted additional 
research on the public availability of energy use data for DAC and 
other facilities, and determined that, with the exception of the state 
and county where the DAC facility is located, the other proposed data 
elements are not consistently available to the public at this time. As 
DAC is a nascent field, there are not yet many examples of such 
facilities to support a determination as to whether the other proposed 
data elements are typically and actually held confidential. The EPA, 
therefore, partially agrees with the commenter that certain data 
elements for DAC process unit energy requirements in 40 CFR 98.426(i) 
may be treated as confidential by certain facilities. The EPA is, 
therefore, making a determination of ``Eligible for Confidential 
Treatment'' for certain data elements. Specifically, the EPA is 
finalizing the rule with all new data elements in 40 CFR 98.426(i) 
having the categorical determination of ``Eligible for Confidential 
Treatment'' except for proposed 40 CFR 98.426(i)(1)(i)(A) and (B), the 
state and county where the DAC process unit is located, and certain 
information reported under 40 CFR 98.426(i)(1) through (3), which 
requires the reporter to indicate each applicable energy source type 
(e.g., natural gas, oil, coal, nuclear) and provide an indication of 
whether flue gas is captured (proposed 40 CFR 98.426(i)(1)), 
respectively. The rule is being finalized with the determination that 
these four data elements are not eligible for confidential treatment. 
The requirements to report the state and county are similar to data 
required to be reported under 40 CFR 98.3(c)(1) that was designated as 
``emission data,'' which under CAA section 114 is not entitled to 
confidential treatment (76 FR 30782, May 26, 2011; CBI Memo, April 29, 
2011). Furthermore, the EPA has previously determined that indication 
of source is not confidential (77 FR 48072, August 13, 2012). Regarding 
reporting whether flue gas is captured, the EPA has previously 
determined that an indication of flue gas is ``Not Eligible'' (76 FR 
30782, May 26, 2011). While the source of energy would be ``Not 
Eligible'' for confidential treatment, the actual quantities of energy 
reported under 40 CFR 98.426(i)(1) through (3) would be ``Eligible for 
Confidential Treatment.'' The EPA will consider revising the 
confidentiality status of the energy consumption data elements in the 
future, as more DAC facilities begin operating and we have a better 
understanding of how these data are customarily treated. For example, 
if DAC facilities begin customarily sharing their energy consumption 
information to advertise their energy efficiency, we may consider 
revising the confidentiality status to ``No Determination'' or ``Not 
Eligible for Confidential treatment.''
    Comment: The EPA received several comments regarding the 
confidential treatment of the proposed EOR OMP at 40 CFR 98.488. 
Several commenters strongly supported the publishing of non-
confidential data related to anthropogenic CO2 volumes 
permanently stored in in CO2-EOR operations, including the 
EOR OMP. Commenters compared the EOR OMP to the MRV plan issued or 
required under subpart RR, noting that the plans serve very similar 
purposes and include a geologic characterization of the storage 
location, information about wells within the storage site area, 
operations history, monitoring programs, and calculation and 
quantification methods used to determine the total amount of 
CO2

[[Page 31881]]

stored in the storage site. One commenter strongly objected to the 
public disclosure of the OMP. The commenter stated that, unlike an MRV 
which must receive approval by the EPA under subpart RR, there is no 
such approval required for an OMP under subpart VV, which is 
appropriate given the differences in the subpart methodologies. The 
commenter added that reporting entities are currently free to exercise 
discretion to publicly disclose their OMPs.
    Response: The EPA disagrees with the commenter. The EPA's review 
and approval of a document does not determine whether the document is 
eligible for confidential treatment. The EPA proposed that the OMP is 
not eligible for confidential treatment because it does not consider 
the data elements in the OMP to be customarily and actually treated as 
confidential. We note that this, rather than whether the EPA reviews 
and approves a submission, is the standard for confidentiality of 
reported data elements based on the Argus Leader decision. For example, 
the OMP shall include geologic characterization of the EOR complex, a 
description of the facilities within the CO2-EOR project, a 
description of all wells and other engineered features in the 
CO2-EOR project, the operations history of the project 
reservoir, descriptions of containment assurance and the monitoring 
plan, mass of CO2 previously injected and other information 
required in the CSA/ANSI ISO 27916:19 standard. This information is 
normally available to the public through geologic records, construction 
and operating permitting files, well permits, tax records, and other 
public records. Furthermore, such information is available in EPA-
approved subpart RR MRV plans which have been determined to be not-
confidential and are consistently made publicly available on the EPA's 
website. That the EPA does not have a role in approving the OMP does 
not mean that the content itself is typically and actually held 
confidential.

C. Final Reporting Determinations for Inputs to Emission Equations

    In the 2022 Data Quality Improvements Proposal and the 2023 
Supplemental Proposal, the EPA proposed to assign several data elements 
to the ``Inputs to Emission Equation'' data category. As discussed in 
section VI.B.1. of the preamble to the 2022 Data Quality Improvements 
Proposal, the EPA determined that the Argus Leader decision does not 
affect our approach for handling of data elements assigned to the 
``Inputs to Emission Equations'' data category. Data assigned to the 
``Inputs to Emission Equations'' data category are assigned to one of 
two subcategories, including ``inputs to emission equations'' that must 
be directly reported to the EPA, and ``inputs to emission equations'' 
that are not reported but are entered into the EPA's Inputs 
Verification Tool (IVT). The EPA received no comments specific to the 
proposed reporting determinations for inputs to emission equations in 
the proposed rules. Additional information regarding these reporting 
determinations may be found in section VI.C. of the preamble to the 
2022 Data Quality Improvements Proposal and the 2023 Supplemental 
Proposal.
    The EPA is finalizing the reporting determinations for data 
elements that the EPA proposed to assign to the ``Inputs to the 
Emission Equation'' data category as they were proposed for all 
subparts with the exception of certain records proposed for subparts G 
(Ammonia Production), P (Hydrogen Production), S (Lime Production), and 
HH (Municipal Solid Waste Landfills). For subparts G, P, and S, the new 
and substantially revised data elements were not proposed to be 
included in the reporting section of those subparts but were instead to 
be retained as records to be input into the EPA's IVT, and the EPA did 
not evaluate these data elements further. The EPA is not taking final 
action on these inputs into IVT because the EPA is not taking final 
action on the requirement to retain these data elements as records (see 
section III. of this preamble for additional information.) For subpart 
HH, the EPA is not finalizing the proposed reporting determinations for 
certain data elements because the EPA is not taking final action on the 
requirements to report these data elements at this time (see section 
III. of this preamble for additional information). These data elements 
are listed in table 3 of the memorandum ``Reporting Determinations for 
Data Elements Assigned to the Inputs to Emission Equations Data 
Category in the 2024 Final Revisions to the Greenhouse Gas Reporting 
Rule,'' available in the docket to this rulemaking, Docket ID. No. EPA-
HQ-OAR-2019-0424.
    In a handful of cases, the EPA has made minor revisions to data 
elements assigned to the ``Inputs to Emissions Equations'' data 
category in this final action as compared to the proposed data element 
included in the 2022 Data Quality Improvements Proposal or the 2023 
Supplemental Proposal. For certain proposed data elements, we have 
revised the citations from proposal to final. In other cases, the minor 
revisions include clarifications to the text. The EPA evaluated these 
inputs to emissions equations and how they have been clarified in the 
final rule to verify that the data element has not substantially 
changed since proposal. These data elements and how they have been 
clarified in the final rule are listed in table 4 of the memorandum 
``Reporting Determinations for Data Elements Assigned to the Inputs to 
Emission Equations Data Category in the 2024 Final Revisions to the 
Greenhouse Gas Reporting Rule,'' available in the docket to this 
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. Because the input has 
not substantially changed since proposal, we are finalizing the 
proposed reporting determinations for these data elements as proposed. 
For additional information on the rationale for the reporting 
determinations for the data elements, see the preamble to the 2022 Data 
Quality Improvements Proposal or the 2023 Supplemental Proposal and the 
memorandums ``Proposed Reporting Determinations for Data Elements 
Assigned to the Inputs to Emission Equations Data Category in Proposed 
Revisions to the Greenhouse Gas Reporting Rule'' and ``Proposed 
Reporting Determinations for Data Elements Assigned to the Inputs to 
Emission Equations Data Category in Proposed Supplemental Revisions to 
the Greenhouse Gas Reporting Rule,'' available in the docket for this 
rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
    For all other reporting determinations for the data elements 
assigned to the ``Inputs to Emission Equations'' data category, the EPA 
is finalizing the reporting determinations as they were proposed. 
Please refer to the preamble to the 2022 Data Quality Improvements 
Proposal or the 2023 Supplemental Proposal for additional information.

VII. Impacts and Benefits of the Final Amendments

    This section of the preamble examines the costs and economic 
impacts of the final rule and the estimated impacts of the rule on 
affected entities, in addition to the benefits of the final rule. The 
revisions in this final rule are anticipated to increase burden in 
cases where the amendments expand the applicability, monitoring, or 
reporting requirements of part 98. In some cases, the final amendments 
are anticipated to decrease burden where we streamlined the rule to 
remove notification or reporting requirements or simplify monitoring 
and reporting requirements. The final rule consolidates amendments

[[Page 31882]]

from the 2022 Data Quality Improvements Proposal and the 2023 
Supplemental Proposal that revise 32 subparts that directly affect 30 
industries--including revisions to update the GWPs in table A-1 to 
subpart A of part 98 that affect the number of facilities required to 
report under part 98; revisions to implement five new source categories 
or to expand existing source categories that may require facilities to 
newly report or to report under new provisions; and revisions to add 
new reporting requirements to a number of subparts that will improve 
the quality of the data collected under part 98. The bulk of costs 
associated with the final rule includes those costs to facilities that 
would be required to newly report under part 98 (subparts I, P, W, DD, 
HH, II, OO, TT, WW, XX, YY, and ZZ). However, the majority of subparts 
affected will reflect a modest increase in burden to individual 
reporters. As discussed in the preamble to the 2022 Data Quality 
Improvements Proposal and the 2023 Supplemental Proposal, in several 
cases the final rule amendments are anticipated to result in a decrease 
in burden. In some cases we have quantified where the final rule would 
result in a decrease in burden for certain reporters, but in other 
cases we were unable to quantify this decrease. The final revisions 
also include minor amendments, corrections, and clarifications, 
including simple revisions of requirements such as clarifying changes 
to definitions, calculation methodologies, monitoring and quality 
assurance requirements, and reporting requirements. These revisions 
clarify part 98 to better reflect the EPA's intent, and do not present 
any additional burden on reporters. The impacts of the final rule 
generally reflect an increase in burden for most subparts.
    The EPA received a number of comments on the proposed revisions and 
the impacts of the proposed revisions in both the 2022 Data Quality 
Improvements Proposal and the 2023 Supplemental Proposal. See the 
document ``Summary of Public Comments and Responses for 2024 Final 
Revisions and Confidentiality Determinations for Data Elements under 
the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-
0424 for a complete listing of all comments and responses related to 
the impacts of the proposed rules. Following consideration of these 
comments, the EPA has, in some cases, revised the final rule 
requirements and updated the impacts analysis to reflect these changes.
    As noted in section I.C. of this preamble, although the EPA 
proposed amendments to subpart W (Petroleum and Natural Gas Systems) in 
the 2022 Data Quality Improvements Proposal, this final rule does not 
address implementation of these revisions to subpart W, which the EPA 
is reviewing in concurrent rulemakings. Additionally, as stated in 
section III.B. of this preamble, the EPA is not taking final action on 
its proposed amendments to add a source category for collection of data 
on energy consumption (subpart B) at this time. Accordingly, the 
impacts of the final rule do not reflect the costs for these proposed 
revisions.
    For some subparts, we are not taking final action on revisions to 
calculation, monitoring, or reporting requirements that would have 
required reporters to collect or submit additional data. For example, 
for subpart C (General Stationary Fuel Combustion), we are not taking 
final action on proposed revisions to (1) add new reporting for the 
unit type, maximum rated heat input capacity, and an estimate of the 
fraction of the total annual heat input from each unit in either an 
aggregation of units or common pipe configuration (excluding units less 
than 10 mmBtu/hour); and (2) add new reporting to identify whether any 
unit in the configuration (individual units, aggregation of units, 
common stack, or common pipe) is an EGU, and, for multi-unit 
configurations, an estimated decimal fraction of total emissions from 
the group that are attributable to EGU(s) included in the group. For 
subparts G (Ammonia Production), P (Hydrogen Production), S (Lime 
Production), and HH (Municipal Solid Waste Landfills) we are not taking 
final action on certain revisions to the calculation methodologies that 
would have revised how data is collected and reported in e-GGRT. 
Similarly, we are not taking final action on certain data elements that 
were proposed to be added to subparts A (General Provisions), F 
(Aluminum Production), G (Ammonia Production), H (Cement Production), 
P, S (Lime Production), HH, OO (Suppliers of Industrial Greenhouse 
Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases 
Contained in Pre-Charged Equipment and Closed-Cell Foams). Therefore, 
the final burden for these subparts has been revised to reflect only 
those requirements that are being finalized, and is lower than 
proposed.
    In a few cases, the EPA has adjusted the burden of the final rule 
to account for additional costs associated with the final rule. In 
these cases, we have made minor adjustments to the reporting and 
recordkeeping requirements in the final rule. Specifically, we are 
finalizing changes from the proposed rule that would add 8 new data 
elements to subparts I, P, DD, and ZZ (see section III. of this 
preamble for additional information). The final rule burden estimate 
has been adjusted to include additional time and labor for these 
activities, which the EPA estimates is minimal for the reasons 
described in section III. of this preamble. Finally, the burden for the 
activities in the final rule has been adjusted to reflect updates to 
the estimated number of affected reporters based on a review of data 
from RY2022 reporting.
    As discussed in section V. of this preamble, the final rule will be 
implemented on January 1, 2025, and will apply to RY2025 reports. Costs 
have been estimated over the three years following the year of 
implementation. One-time implementation costs are incorporated into 
first year costs, while subsequent year costs represent the annual 
burden that will be incurred in total by all affected reporters. The 
incremental implementation labor costs for all subparts include 
$2,684,681 in RY2025, and $2,671,831 in each subsequent year (RY2026 
and RY2027). The incremental implementation labor costs over the next 
three years (RY2025 through RY2027) total $8,028,343. There is an 
additional incremental burden of $2,733,937 for capital and O&M costs 
in RY2025 and in each subsequent year (RY2026 and RY2027), which 
reflects changes to applicability and monitoring for subparts I, P, W, 
V, Y, DD, HH, II, OO, TT, UU and new subparts VV, WW, XX, YY, and ZZ. 
The incremental non-labor costs for RY2025 through RY2027 total 
$8,201,812 over the next three years. The incremental burden is 
summarized by subpart for the rule changes that are finalized for 
initial and subsequent years in table 8 of this preamble. Note that 
subparts A, U, FF, and RR only include revisions that are 
clarifications or harmonizing changes that would not result in any 
changes to burden, and are not included in table 8 of this preamble.

[[Page 31883]]



                        Table 8--Annual Incremental Burden of the Final Rule, by Subpart
----------------------------------------------------------------------------------------------------------------
                                                                            Labor costs
                                                     Number of   --------------------------------   Capital and
                     Subpart                         affected                       Subsequent          O&M
                                                    facilities     Initial year        years
----------------------------------------------------------------------------------------------------------------
C--General Stationary Fuel Combustion Sources     ..............  ..............  ..............  ..............
 \a\............................................
Facilities Reporting only to Subpart C..........             133        ($1,446)        ($1,446)  ..............
Facilities Reporting to Subpart C plus another               177           (979)           (979)  ..............
 subpart........................................
G--Ammonia Manufacturing........................              29             119             119  ..............
H--Cement Production............................              94           1,999           1,999  ..............
I--Electronics Manufacturing \b\ \c\............              48          19,651          18,023             $62
N--Glass Production.............................             101           2,074           2,074  ..............
P--Hydrogen Production \b\......................             114           7,497           7,497           2,561
Q--Iron and Steel Production....................             121           1,485           1,485  ..............
S--Lime Manufacturing...........................              71           1,186           1,186  ..............
V--Nitric Acid Production \d\ \e\...............               1         (2,680)         (2,680)        (11,085)
W--Petroleum and Natural Gas Systems \d\........             188       2,433,058       2,433,058       2,717,864
X--Petrochemical Production.....................              31             618             618  ..............
Y--Petroleum Refineries \f\.....................              57         (6,133)         (6,133)         (3,930)
AA--Pulp and Paper Manufacturing................               1             104             104  ..............
BB--Silicon Carbide Production..................               1              20              20  ..............
DD--Electrical Transmission \b\.................              95          15,278          15,278           3,119
GG--Zinc Production.............................               5              20              20  ..............
HH--Municipal Solid Waste Landfills \b\.........           1,129          84,651          81,793             374
II--Industrial Wastewater Treatment \d\.........               2           5,288           4,713           3,077
OO--Suppliers of Industrial Greenhouse Gases \a\             121           6,884           6,884              62
PP--Suppliers of Carbon Dioxide.................              22             872             872  ..............
QQ--Importers and Exporters of Fluorinated                    33             249             249  ..............
 Greenhouse Gases Contained in Pre-Charged
 Equipment or Closed-Cell Foams.................
SS--Electrical Equipment Manufacture or                        5             358             358  ..............
 Refurbishment..................................
TT--Industrial Waste Landfills \b\ \d\..........               1           4,853           3,934              62
UU--Injection of Carbon Dioxide \g\.............               2         (1,886)         (1,886)           (125)
VV--Geologic Sequestration of Carbon Dioxide                   2           1,882           3,443             250
 with Enhanced Oil Recovery Using ISO 27916 \g\.
WW--Coke Calciners..............................              15          37,847          34,525          19,649
XX--Calcium Carbide Production..................               1           2,849           2,627              62
YY--Caprolactam, Glyoxal, and Glyoxylic Acid                   6          12,285          11,089             374
 Production.....................................
ZZ--Ceramics Manufacturing......................              25          56,678          52,987           1,559
                                                 ---------------------------------------------------------------
    Total.......................................  ..............       2,684,681       2,671,831       2,733,937
----------------------------------------------------------------------------------------------------------------
\a\ Reflects reduced burden due to revisions to simplify calculation methods and remove reporting requirements.
\b\ Applies to reporters that may currently report under existing subparts of part 98 and that are newly subject
  to reporting under part 98.
\c\ Average subsequent year costs for subpart I. Subpart I subsequent year costs include $17,794 in Year 2 and
  $18,252 in Year 3.
\d\ Reflects burden to reporters estimated to be affected due to revisions to table A-1 to subpart A only.
\e\ Reflects changes to the number of reporters able to off-ramp from reporting under the part 98 source
  category.
\f\ Reflects changes to the number of reporters with coke calciners reporting under subpart Y that would be
  required to report under proposed subpart WW.
\g\ Reflects changes to the number of reporters reporting under subpart UU who will begin submitting reports
  under new subpart VV in each year.

    Additional details on the EPA's review of the impacts may be found 
in the memorandum, ``Assessment of Burden Impacts for Final Revisions 
to the Greenhouse Gas Reporting Rule,'' available in Docket ID. No. 
EPA-HQ-OAR-2019-0424.
    The implementation of the final rule will provide numerous benefits 
for stakeholders, the Agency, industry, and the general public. The 
final revisions include improvements to the calculation, monitoring, 
and reporting requirements, incorporate new data and reflect updated 
scientific knowledge; provide coverage of new emissions sources and 
additional sectors; improve analysis and verification of collected 
data; provide additional data to complement or inform other EPA 
programs; and streamline calculation, monitoring, or reporting to 
provide flexibility or increase the efficiency of data collection. The 
revisions will maintain the quality of the data collected under part 98 
where continued collection of information assists in evaluation and 
support of EPA programs and policies under provisions of the CAA. In 
some cases, the amendments improve the EPA's ability to assess 
compliance by revising or adding recordkeeping or reporting elements 
that will allow the EPA to more thoroughly verify GHG data and advance 
the ability of the GHGRP to provide access to quality data on 
greenhouse gas emissions by adding or updating emission factors, 
revising or adding calculation methodologies, or adding key data 
elements to improve the usefulness of the data.
    Because part 98 is a reporting rule, the EPA did not quantify 
estimated emission reductions or monetize the benefits from such 
reductions that could be associated with the final rule. The benefits 
of the final rule are based on its relevance to policy making, 
transparency, and market efficiency. The improvements to the GHGRP will 
benefit the EPA, other policymakers, and the public by increasing the 
completeness and accuracy of facility emissions data. Public data on 
emissions allows for accountability of emitters to the public. Improved 
facility-specific emissions data will aid local, state, and national 
policymakers as they evaluate and consider future climate change policy 
decisions and other policy decisions for criteria pollutants, ambient 
air quality standards, and toxic

[[Page 31884]]

air emissions. For example, GHGRP data on petroleum and natural gas 
systems (subpart W of part 98) were previously analyzed to inform 
targeted improvements to the 2016 NSPS for the oil and gas industry and 
to update emission factor and activity data used for that proposal and 
the final NSPS, as updated in the Inventory (83 FR 52056; October 15, 
2018). Similarly, GHGRP data on municipal solid waste landfills 
(subpart HH of part 98) were previously used to inform the development 
of the 2016 NSPS and EG for landfills; the EPA was able to update its 
internal landfills data set and consider the technical attributes of 
over 1,200 landfills based on data reported under subpart HH. The 
benefits of improved reporting also include enhancing existing 
voluntary programs, such as the Landfill Methane Outreach Program 
(LMOP), which uses GHGRP data to supplement the LMOP Landfill and 
Landfill Gas Energy Project Database and includes data collected from 
LMOP Partners about landfill gas energy projects or potential for 
project development.
    The final rule would additionally benefit states by providing 
improved facility-specific emissions data. Several states use GHGRP 
data to inform their own policymaking. For example, the state of Hawaii 
uses GHGRP data to establish an emissions baseline for each facility 
subject to their GHG Reduction Plan and to assess whether facilities 
meet their targets in future years.
    GHGRP data are also used to improve estimates of GHG emissions 
internationally. Data collected through the GHGRP complements the 
Inventory and are used to significantly improve our understanding of 
key emissions sources by allowing the EPA to better reflect changing 
technologies and emissions from a wide range of industrial facilities. 
Specifically, GHGRP data have been used to inform several of the 
updates to emission estimation methods included in the 2019 Refinement.
    Benefits to industry of improved GHG emissions monitoring and 
reporting from the amendments include the value of having standardized 
emissions data to present to the public to demonstrate appropriate 
environmental stewardship, and a better understanding of their emission 
levels and sources to identify opportunities to reduce emissions. For 
example, the final rule updates the global warming potential values 
used under the GHGRP to reflect values from the IPCC AR5 and AR6, which 
are consistent with the values used under several voluntary standards 
and frameworks such as the GHG Protocol and Sustainability Accounting 
Standards Board (SASB), and will provide consistency for company 
reporting. Businesses and other innovators can use the data to 
determine and track their GHG footprints, find cost-saving efficiencies 
that reduce GHG emissions and save product, foster technologies to 
protect public health and the environment, and to reduce costs 
associated with fugitive emissions. The final rule will continue to 
allow for facilities to benchmark themselves against similar facilities 
to understand better their relative standing within their industry and 
achieve and disseminate information about their environmental 
performance.
    In addition, transparent, standardized public data on emissions 
allows for accountability of polluters to the public who bear the cost 
of the pollution. The GHGRP serves as a powerful data resource and 
provides a critical tool for communities to identify nearby sources of 
GHGs and provide information to state and local governments. As 
discussed in section II. of this preamble, GHGRP data are easily 
accessible to the public via the EPA's FLIGHT, which allows users to 
view and sort GHG data by location, industrial sector, and type of GHG 
emitted, and includes demographic data. Although the emissions reported 
to the EPA by reporting facilities are global pollutants, many of these 
facilities also release pollutants that have a more direct and local 
impact in the surrounding communities. Citizens, community groups, and 
labor unions have made use of public pollutant release data to 
negotiate directly with emitters to lower emissions, avoiding the need 
for additional regulatory action. The final rule would improve the 
quality and transparency of this reported data to affected communities.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 14094: 
Modernizing Regulatory Review

    This action is not a significant regulatory action as defined in 
Executive Order 12866, as amended by Executive Order 14094, and was 
therefore not subject to a requirement for Executive Order 12866 
review.

B. Paperwork Reduction Act

    The information collection activities in this rule have been 
submitted for approval to the OMB under the PRA. The Information 
Collection Request (ICR) document that the EPA prepared has been 
assigned OMB number 2060-0748, EPA ICR number 2773.02. You can find a 
copy of the ICR in the docket for this rule, and it is briefly 
summarized here. The information collection requirements are not 
enforceable until OMB approves them.
    The EPA has estimated that the final rule will result in an 
increase in burden, specifically in cases where the amendments expand 
the applicability, monitoring, or reporting requirements of part 98. In 
some cases, the final amendments are anticipated to decrease burden 
where we streamlined the rule to remove notification or reporting 
requirements or simplify monitoring and reporting requirements. The 
final rule consolidates amendments from the 2022 Data Quality 
Improvements Proposal and the 2023 Supplemental Proposal that revise 31 
subparts that directly affect 30 industries--including revisions to 
update the GWPs in table A-1 to subpart A of part 98 that affect the 
number of facilities required to report under part 98; revisions to 
implement five new source categories or to expand existing source 
categories that may require facilities to newly report; and revisions 
to add new reporting requirements that will improve the quality of the 
data collected under part 98. The costs associated with the final rule 
largely reflect the costs to facilities that would be required to newly 
report under part 98. However, the majority of subparts affected will 
reflect a modest increase in burden to existing individual reporters.
    Further information on the EPA's assessment on the impact on burden 
can be found in the memorandum ``Assessment of Burden Impacts for Final 
Revisions for the Greenhouse Gas Reporting Rule,'' available in the 
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
    Respondents/affected entities: Owners and operators of facilities 
that must report their GHG emissions and other data to the EPA to 
comply with 40 CFR part 98.
    Respondent's obligation to respond: The respondent's obligation to 
respond is mandatory and the requirements in this rule are under the 
authority provided in CAA section 114.
    Estimated number of respondents: 2,701.
    Frequency of response: Initially, annually.
    Total estimated burden: 25,647 hours (annual average per year). 
Burden is defined at 5 CFR 1320.3(b).
    Total estimated cost: $5,410,000 (annual average per year), 
includes $2,734,000 annualized capital or operation and maintenance 
costs.
    An agency may not conduct or sponsor, and a person is not required 
to

[[Page 31885]]

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. When OMB approves 
this ICR, the Agency will announce that approval in the Federal 
Register and publish a technical amendment to 40 CFR part 9 to display 
the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this final action will not have a significant 
economic impact on a substantial number of small entities under the 
RFA. The small entities subject to the requirements of this action are 
small businesses across all sectors encompassed by the rule, small 
governmental jurisdictions, and small non-profits. In the development 
of 40 CFR part 98, the EPA determined that some small entities are 
affected because their production processes emit GHGs that must be 
reported, because they have stationary combustion units on site that 
emit GHGs that must be reported, or because they have fuel supplier 
operations for which supply quantities and GHG data must be reported. 
Small governments and small non-profits are generally affected because 
they have regulated landfills or stationary combustion units on site, 
or because they own a local distribution company (LDC).
    The EPA previously conducted screening analyses to identify impacts 
to small entities during the development of the 2022 Data Quality 
Improvements Proposal and the 2023 Supplemental Proposal. The EPA 
conducted small entity analyses that assessed the costs and impacts to 
small entities in three areas, including: (1) amendments that revise 
the number or types of facilities required to report (i.e., updates of 
the GHGRP's applicability to certain sources), (2) changes to refine 
existing monitoring or calculation methodologies that require 
collection of additional data, and (3) revisions to reporting and 
recordkeeping requirements for data provided to the program. The 
analyses provided the subparts affected, the number of small entities 
affected, and the estimated impact to these entities based on the total 
annualized reporting costs of the proposed rules. Details of these 
analyses are presented in the memoranda, Assessment of Burden Impacts 
for Proposed Revisions for the Greenhouse Gas Reporting Rule (May 2022) 
and Assessment of Burden Impacts for Proposed Supplemental Revisions 
for the Greenhouse Gas Reporting Rule (April 2023), available in the 
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424). Based 
on the results of these analyses, we concluded that the 2022 Data 
Quality Improvements Proposal and 2023 Supplemental Proposal will have 
no significant regulatory burden for any directly regulated small 
entities and thus would not have a significant economic impact on a 
substantial number of small entities.
    As discussed in sections III. and VII. of this preamble, this 
action finalizes revisions to part 98 as proposed in the 2022 Data 
Quality Improvements Proposal and the 2023 Supplemental Proposal, or 
with minor revisions, and we have revised the cost impacts to reflect 
the final rule requirements and more recent data. For example, we have 
updated the impacts to better reflect the number of affected reporters 
that would be subject to the final requirements, based on a review of 
RY2022 data. These updates also predominantly include removing or 
adjusting costs where the EPA is not taking final action on specific 
proposed revisions, including costs associated with the addition of 
proposed subpart B (Energy Consumption), certain costs associated with 
proposed revisions to subpart W (Petroleum and Natural Gas Systems) 
included in the 2022 Data Quality Improvements Proposal,\50\ and costs 
associated with certain revisions to calculations, monitoring, or 
reporting requirements for subparts A (General Provisions), C (General 
Stationary Fuel Combustion), F (Aluminum Production), G (Ammonia 
Production), H (Cement Production), S (Lime Production), HH (Municipal 
Waste Landfills), OO (Suppliers of Industrial Greenhouse Gases), and QQ 
(Importers and Exporters of Fluorinated Greenhouse Gases Contained in 
Pre-Charged Equipment and Closed-Cell Foams). Accordingly, the burden 
of the final rule is reduced, as compared to the proposals, for 
facilities that may report for these source categories, including all 
direct emitting facilities previously proposed to report under subpart 
B.
---------------------------------------------------------------------------

    \50\ The EPA is not taking final action on any revisions to 
requirements for subpart W (Petroleum and Natural Gas Systems) in 
this final rule. See sections I.C. and VII. of this preamble for 
additional information regarding the EPA's actions regarding subpart 
W and the impacts included in this final rule.
---------------------------------------------------------------------------

    The EPA has also adjusted the burden to account for additional 
costs from changes adopted in the final rule. Specifically, we have 
adjusted the reporting and recordkeeping requirements for subparts I 
(Electronics Manufacturing), P (Hydrogen Production), DD (Electrical 
Transmission and Distribution Equipment Use), HH (Municipal Solid Waste 
Landfills), and ZZ (Ceramics Manufacturing) to add new data elements 
for annual reporting across these subparts. The estimated costs 
associated with the revisions to these subparts for regulated entities 
are minimal (less than $100 annually), and would not result in costs 
exceeding more than one percent of sales in any firm size category. 
Details of this analysis are presented in the memorandum ``Assessment 
of Burden Impacts for Final Revisions for the Greenhouse Gas Reporting 
Rule,'' available in Docket ID. No. EPA-HQ-OAR-2019-0424.
    The remaining revisions to the final rule include minor 
clarifications or adjustments to the proposed requirements that are not 
anticipated to increase the burdens estimated for the 2022 Data Quality 
Improvements Proposal and 2023 Supplemental Proposal which we 
previously determined would not have a significant impact on a 
significant number of small businesses. For these reasons, we have 
determined that these final revisions are consistent with our prior 
small entity analyses, and would impose no significant regulatory 
burden on any directly regulated small entities, and thus would not 
have a significant economic impact on a substantial number of small 
entities.
    Refer to the memorandum ``Assessment of Burden Impacts for Final 
Revisions for the Greenhouse Gas Reporting Rule,'' available in Docket 
ID. No. EPA-HQ-OAR-2019-0424 for further discussion. The EPA continues 
to conduct significant outreach on the GHGRP and maintains an ``open 
door'' policy for stakeholders to help inform the EPA's understanding 
of key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments.

E. 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.

[[Page 31886]]

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

    This action has tribal implications. However, it will neither 
impose substantial direct compliance costs on federally recognized 
tribal governments, nor preempt tribal law. This regulation will apply 
directly to facilities emitting and supplying GHGs that may be owned by 
tribal governments that emit GHGs. However, it will only have tribal 
implications where the tribal entity owns a facility that directly 
emits GHGs above threshold levels; therefore, relatively few 
(approximately 10) tribal facilities will be affected. This regulation 
is not anticipated to impact facilities or suppliers of additional 
sectors owned by tribal governments.
    In evaluating the potential implications for tribal entities, we 
first assessed whether tribes would be affected by any final revisions 
that expanded the universe of facilities that would report GHG data to 
the EPA. The final rule amendments will implement requirements to 
collect additional data to understand new source categories, new 
sources of GHG emissions or supply for specific sectors; improve the 
existing emissions estimation methodologies; and improve the EPA's 
understanding of the sector-specific processes or other factors that 
influence GHG emission rates and improve verification of collected 
data. Of the 254 facilities that we anticipate will be newly required 
to report under the final revisions, we do not anticipate that there 
are any tribally owned facilities. As discussed in section VII. of this 
preamble, we expect the final revisions to table A-1 to part 98 to 
result in a change to the number of facilities required to report under 
subparts W (Petroleum and Natural Gas Systems), V (Nitric Acid 
Production), DD (Electrical Transmission and Distribution Equipment 
Use), HH (MSW Landfills), II (Industrial Wastewater Treatment), OO 
(Suppliers of Industrial GHGs), and TT (Industrial Waste Landfills). 
However, we did not identify any potential sources in these source 
categories that are owned by tribal entities not already reporting to 
the GHGRP. Similarly, although we are finalizing amendments that will 
require some facilities in select source categories not currently 
subject to the GHGRP to begin implementing requirements under the 
program, we have not identified, and do not anticipate that any of 
these affected facilities are owned by tribal governments.
    As a second step to evaluate potential tribal implications, we 
evaluated whether there were any tribally owned facilities that are 
currently reporting under the GHGRP that will be affected by the final 
revisions. Tribally owned facilities currently subject to part 98 will 
only be subject to changes that are improvements or clarifications of 
requirements and that, for the most part, do not significantly change 
the existing requirements or result in substantial new activities 
because they do not require new equipment, sampling, or monitoring. 
Rather, tribally owned facilities would only be subject to new 
requirements where reporters would provide data that is readily 
available from company records. As such, the final revisions will not 
substantially increase reporter burden, impose significant direct 
compliance costs for tribal facilities, or preempt tribal law.
    Specifically, we identified ten facilities currently reporting to 
part 98 that are owned by six tribal parent companies. For these six 
parent companies, we identified facilities in the stationary fuel 
combustion (subpart C), cement production (subpart H), petroleum and 
natural gas (subpart W), electrical transmission and distribution 
equipment use (subpart DD), and MSW landfill (subpart HH) source 
categories that may be affected by the final revisions.
    For stationary fuel combustion, the EPA is not taking final action 
on proposed revisions to add reporting requirements to subpart C, but 
is retaining revisions that would remove certain reporting 
requirements. Therefore, the costs for any tribally-owned facilities 
currently reporting to subpart C are anticipated to decrease and no 
facilities are anticipated to be negatively impacted. For petroleum and 
natural gas facilities, the EPA is not including any revisions to 
subpart W in this final rule (see section I.C. of this document); 
therefore, any tribally-owned facilities currently reporting to subpart 
W are not anticipated to be impacted. Three parent companies include 
existing facilities that report only under subparts C or W, which are 
not anticipated to have significant impacts under this rule for the 
reasons discussed in this section. Therefore, the remaining facilities 
that could be affected by the final revisions are those that report to 
subparts H, DD, and HH. For the remaining three parent companies, we 
reviewed publicly available sales and revenue data to assess whether 
the costs of the final rule would be significant. Under the final rule, 
the costs for facilities currently reporting under subparts H, DD, or 
HH are anticipated to increase by less than $100 per year per subpart. 
Therefore, we were able to confirm that the costs of the final 
revisions would not have a significant impact for these sources. 
Further, based on our review of our small entity analyses (discussed in 
VIII.C. of this preamble), we do not anticipate the final revisions to 
subparts H, DD, or HH will impose substantial direct compliance costs 
on the remaining tribally owned entities.
    Although few facilities subject to part 98 are likely to be owned 
by tribal governments, the EPA previously sought opportunities to 
provide information to tribal governments and representatives during 
the development of the proposed and final rules for part 98 subparts 
that were promulgated on October 30, 2009 (74 FR 52620), July 12, 2010 
(75 FR 39736), November 30, 2010 (75 FR 74458), and December 1, 2010 
(75 FR 74774 and 75 FR 75076). Consistent with the 2011 EPA Policy on 
Consultation and Coordination with Indian Tribes,\51\ the EPA 
previously consulted with tribal officials early in the process of 
developing part 98 regulations to permit them to have meaningful and 
timely input into its development and to provide input on the key 
regulatory requirements established for these facilities. A summary of 
these consultations is provided in section VIII.F. of the preamble to 
the final rule published on October 30, 2009 (74 FR 52620), section 
V.F. of the preamble to the final rule published on July 12, 2010 (75 
FR 39736), section IV.F. of the preamble to the re-proposal of subpart 
W (Petroleum and Natural Gas Systems) published on April 12, 2010 (75 
FR 18608), and section IV.F. of the preambles to the final rules 
published on December 1, 2010 (75 FR 74774 and 75 FR 75076). As 
described in this section, the final rule does not significantly revise 
the established regulatory requirements and will not substantially 
change the equipment, monitoring, or reporting activities conducted by 
these facilities, or result in other substantial impacts for tribal 
facilities.
---------------------------------------------------------------------------

    \51\ EPA Policy on Consultation and Coordination with Indian 
Tribes, May 4, 2011. Available at: www.epa.gov/sites/default/files/2013-08/documents/cons-and-coord-with-indian-tribes-policy.pdf.
---------------------------------------------------------------------------

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

    The EPA interprets Executive Order 13045 as applying only 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

[[Page 31887]]

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.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not subject to Executive Order 13211, because it is 
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act and 1 CFR Part 51

    This action involves technical standards. The EPA has decided to 
incorporate by reference several standards in establishing monitoring 
requirements in these final amendments.
    The EPA currently allows for the use of the Protocol for Measuring 
Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas 
Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-
10-003, March 2010 (EPA 430-R-10-003) in other sections of part 98, 
including subpart I (Electronics Manufacturing). The EPA is adding the 
use of EPA 430-R-10-003 to subpart I for use for measurement of DREs 
from abatement systems, including HC fuel CECS, purchased and installed 
on or after January 1, 2025. EPA 430-R-10-003 provides methods for 
measuring abatement system inlet and outlet mass or volume flows for 
single or multi-chamber process tools, accounting for dilution. Anyone 
may access EPA 430-R-10-003 at https://www.epa.gov/sites/default/files/2016-02/documents/dre_protocol.pdf. This standard is available to 
everyone at no cost; therefore, the method is reasonably available for 
reporters.
    The EPA is allowing the use of an alternate method, ASTM E415-17, 
Standard Test Method for Analysis of Carbon and Low-Alloy Steel by 
Spark Atomic Emission Spectrometry (2017), for the purposes of subpart 
Q (Iron and Steel Production) monitoring and reporting. The EPA 
currently allows for the use of ASTM E415-17 in other sections of part 
98, including under 40 CFR 98.144(b) where it can be used to determine 
the composition of coal, coke, and solid residues from combustion 
processes by glass production facilities. Therefore, the EPA is 
allowing ASTM E415-17 to be used in subpart Q. ASTM E415-17 uses spark 
atomic emission vacuum spectrometry to determine 21 alloying and 
residual elements in carbon and low-alloy steels. The method is 
designed for chill-cast, rolled, and forged specimens. (See the end of 
section VIII.I. of this preamble for availability information.)
    The EPA is adding new subpart VV to part 98 for certain EOR 
operations that choose to use the co-published ISO/CSA standard 
designated as CSA/ANSI ISO 27916:19, Carbon dioxide capture, 
transportation and geological storage--Carbon dioxide storage using 
enhanced oil recovery (CO2-EOR), as a means of quantifying 
geologic sequestration. The EPA is also clarifying in subpart UU at 40 
CFR 98.470(c) and subpart VV at 40 CFR 98.481 that CO2-EOR 
projects previously reporting under subpart UU that begin using CSA/
ANSI ISO 27916:19 part-way through a reporting year must report under 
subpart UU for the portion of the year before CSA/ANSI ISO 27916:19 was 
used and report under subpart VV for the portion of the year once CSA/
ANSI ISO 27916:19 began to be used and thereafter. CSA/ANSI ISO 
27916:19 identifies and quantifies CO2 losses (including 
fugitive emissions) and quantifies the amount of CO2 stored 
in association with the CO2-EOR project. It also shows how 
allocation rations can be used to account for the anthropogenic portion 
of the stored CO2. Anyone may access the standard on the CSA 
group website (www.csagroup.org/store) for additional information. The 
standard is available to everyone at a cost determined by CSA Group 
($225). CSA Group also offers memberships or subscriptions for reduced 
costs. Because the use of the standard is optional, the cost of 
obtaining this standard is not a significant financial burden.
    The EPA is adding new subpart WW to part 98 (Coke Calciners) and is 
allowing the use of any one of the following standards for coke 
calcining facilities: (1) ASTM D3176-15 Standard Practice for Ultimate 
Analysis of Coal and Coke, (2) ASTM D5291-16 Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, and (3) ASTM D5373-21 Standard Test 
Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis 
Samples of Coal and Carbon in Analysis Samples of Coal and Coke. These 
methods are used to determine the carbon content of petroleum coke. The 
EPA currently allows for the use of an earlier version of these 
standard methods for the instrumental determination of carbon content 
in laboratory samples of petroleum coke in other sections of part 98, 
including the use of ASTM D3176-89, ASTM D5291-02, and ASTM D5373-08 in 
40 CFR 98.244(b) (subpart X--Petrochemical Production) and 40 CFR 
98.254(i) (subpart Y--Petroleum Refineries). The EPA is allowing the 
use of the updated versions of these standards (ASTM D3176-15, ASTM 
D5291-16, and ASTM D5373-21) to determine the carbon content of 
petroleum coke for subpart WW (Coke Calciners). ASTM D3176-15 provides 
direction for a convenient and uniform system of analysis of the ash 
content and the content of organic constituents in coal and coke; this 
method references the appropriate ASTM methods for sample collection, 
preparation, content determination, and provides consistency measures 
for calculation and reporting of results. ASTM D5291-16 provides a 
series of test methods for the simultaneous instrumental determination 
of carbon, hydrogen, and nitrogen in petroleum products and lubricants 
such as crude oils, fuel oils, additives, and residues; the method 
allows for a variety of instrumental components and configurations for 
measurement and calculation of concentrations of carbon, hydrogen, and 
nitrogen. ASTM D5373-21 provides a methodology for the determination of 
carbon, hydrogen, and nitrogen content in coal or carbon in coke using 
furnace combustion and instrument detection systems; the method 
addresses the determination of carbon in the range of 54.9 percent m/m 
to 84.7 percent m/m, hydrogen in the range of 3.26 percent m/m to 5.08 
percent m/m, and nitrogen in the range of 0.57 percent m/m to 1.76 
percent m/m in the analysis sample of coal. (See the end of section 
VIII.I. of this preamble for availability information.)
    We are allowing the use of the following standard for coke 
calciners subject to subpart WW: NIST HB 44-2023, NIST Handbook 44: 
Specifications, Tolerances, and Other Technical Requirements For 
Weighing and Measuring Devices, 2023 edition. The EPA currently allows 
for the use of an earlier version of the proposed standard method, 
Specifications, Tolerances, and Other Technical Requirements For 
Weighing and Measuring Devices, NIST Handbook 44 (2009), for the 
calibration and maintenance of instruments used for weighing of mass of 
samples of petroleum coke in other sections of part 98, including 40 
CFR 98.244(b) (subpart X). The EPA is allowing the use of the updated 
version of this standard, NIST HB 44-2023: Specifications, Tolerances, 
and Other Technical Requirements For Weighing and Measuring Devices, 
2023 edition, for performing mass measurements of petroleum coke for 
subpart WW (Coke Calciners). This

[[Page 31888]]

standard includes specifications on design of equipment, tolerances to 
limit the allowable error, sensitivity requirements, and other 
technical requirements for weighing and measuring devices. Anyone may 
access the standards on the NIST website (www.nist.gov/) for 
additional information. These standards are available to everyone at no 
cost; therefore the methods are reasonably available for reporters.
    The EPA is adding new subpart XX to part 98 (Calcium Carbide 
Production) and is allowing the use of one of the following standards 
for calcium carbide production facilities: (1) ASTM D5373-08 Standard 
Test Methods for Instrumental Determination of Carbon, Hydrogen, and 
Nitrogen in Laboratory Samples of Coal, or (2) ASTM C25-06, Standard 
Test Methods for Chemical Analysis of Limestone, Quicklime, and 
Hydrated Lime. ASTM D5373-08 addresses the determination of carbon in 
the range of 54.9 percent m/m to 84.7 percent m/m, hydrogen in the 
range of 3.25 percent m/m to 5.10 percent m/m, and nitrogen in the 
range of 0.57 percent m/m to 1.80 percent m/m in the analysis sample of 
coal. The EPA currently allows for the use of ASTM D5373-08 in other 
sections of part 98, including in 40 CFR 98.244(b) (subpart X--
Petrochemical Production), 40 CFR 98.284(c) (subpart BB--Silicon 
Carbide Production), and 40 CFR 98.314(c) (subpart EE--Titanium 
Production) for the instrumental determination of carbon content in 
laboratory samples. Therefore, we are allowing the use of ASTM D5373-08 
for determination of carbon content of materials consumed, used, or 
produced at calcium carbide facilities.
    The EPA currently allows for the use of ASTM C25-06 in other 
sections of part 98, including in 40 CFR 98.194(c) (subpart S--Lime 
Production) for chemical composition analysis of lime products and 
calcined byproducts and in 40 CFR 98.184(b) (subpart R--Lead 
Production) for analysis of flux materials such as limestone or 
dolomite. ASTM C25-06 addresses the chemical analysis of high-calcium 
and dolomitic limestone, quicklime, and hydrated lime. We are allowing 
the use of ASTM C25-06 for determination of carbon content of materials 
consumed, used, or produced at calcium carbide facilities, including 
analysis of materials such as limestone or dolomite.
    Anyone may access the standards on the ASTM website (www.astm.org/) 
for additional information. These standards are available to everyone 
at a cost determined by the ASTM (between $48 and $92 per standard). 
The ASTM also offers memberships or subscriptions that allow unlimited 
access to their methods. The cost of obtaining these methods is not a 
significant financial burden, making the methods reasonably available 
for reporters.
    The EPA will also make a copy of these documents available in hard 
copy at the appropriate EPA office (see the FOR FURTHER INFORMATION 
CONTACT section of this preamble for more information) for review 
purposes only. The EPA is not requiring the use of specific consensus 
standards for new subparts YY (Caprolactam, Glyoxal, and Glyoxylic Acid 
Production) or ZZ (Ceramics Manufacturing), or for other amendments to 
part 98.
    The following standards appear in the amendatory text of this 
document and were previously approved for the locations in which they 
appear:
     ASTM D3176-89 (Reapproved 2002) Standard Practice for 
Ultimate Analysis of Coal and Coke;
     ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants;
     ASTM E1019-08 Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques;
     Specifications, Tolerances, and Other Technical 
Requirements For Weighing and Measuring Devices, NIST Handbook 44 
(2009);
     ASTM D6866-16 Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using 
Radiocarbon Analysis).
     ASTM D7459-08 Standard Practice for Collection of 
Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-
Derived Carbon Dioxide Emitted from Stationary Emissions Sources.
     ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity 
Ethylene by Gas Chromatography.
     T650 om-05 Solids Content of Black Liquor, TAPPI.

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

    The EPA believes that this type of action does not directly concern 
human health or environmental conditions and therefore cannot be 
evaluated with respect to potentially disproportionate and adverse 
effects on communities with environmental justice concerns. This action 
does not affect the level of protection provided to human health or the 
environment, but instead, addresses information collection and 
reporting procedures. Although this action does not concern human 
health or environmental conditions, the EPA identified and addressed 
environmental justice concerns by promoting meaningful engagement from 
communities in developing the action, and in developing requirements 
that improve the quality of data available to communities. The EPA 
provided multiple public comment periods on the proposed 2022 Data 
Quality Improvements Proposal (from June 21, 2022 to October 6, 2022) 
and the 2023 Supplemental Proposal (May 22, 2023 to July 21, 2023), and 
provided opportunities for virtual public hearing(s) for members of the 
public to share information or concerns and participate in the 
decision-making process. Further, the EPA has developed improvements to 
the GHGRP that benefit the public by increasing the completeness and 
accuracy of facility emissions data. The data collected through this 
action will provide an important data resource for communities and the 
public to understand GHG emissions, including requiring reporting of 
GHG data from additional emission sources and providing more 
comprehensive coverage of U.S. GHG emissions. Transparent, standardized 
public data on emissions allows for accountability of polluters to the 
public who bear the cost of the pollution. Although the emissions 
reported to the EPA by reporting facilities are global pollutants, many 
of these facilities also release pollutants that have a more direct and 
local impact in the surrounding communities. GHGRP data are easily 
accessible to the public via the EPA's online data publication tool 
(FLIGHT), which allows users to view and sort GHG data from over 8,000 
entities in a variety of ways including by location, industrial sector, 
type of GHG emitted, and provides supplementary demographic data that 
may be useful to communities with environmental justice concerns. As 
described further in sections II. and III. of this preamble, the final 
rule improves the quality and transparency of this reported data to 
affected communities and enables members of the public to have access 
to and improve their understanding of GHG emissions and pollutants that 
may impact them.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the

[[Page 31889]]

Comptroller General of the United States. This action is not a ``major 
rule'' as defined by 5 U.S.C. 804(2).

L. Judicial Review

    Under CAA section 307(b)(1), any petition for review of this final 
rule must be filed in the U.S. Court of Appeals for the District of 
Columbia Circuit by June 24, 2024. This final rule establishes 
requirements applicable to owners and operators of facilities and 
suppliers in many industry source categories located across the United 
States that are subject to 40 CFR part 98 and therefore is ``nationally 
applicable'' within the meaning of CAA section 307(b)(1).
    Further, pursuant to CAA section 307(d)(1)(V), the Administrator 
has determined that this rule is subject to the provisions of CAA 
section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 
307(d) apply to ``such other actions as the Administrator may 
determine''). Under CAA section 307(d)(7)(B), only an objection to this 
final rule that was raised with reasonable specificity during the 
period for public comment can be raised during judicial review. CAA 
section 307(d)(7)(B) also provides a mechanism for the EPA to convene a 
proceeding for reconsideration, ``[i]f the person raising an objection 
can demonstrate to EPA that it was impracticable to raise such 
objection within [the period for public comment] or if the grounds for 
such objection arose after the period for public comment (but within 
the time specified for judicial review) and if such objection is of 
central relevance to the outcome of the rule.'' Any person seeking to 
make such a demonstration should submit a Petition for Reconsideration 
to the Office of the Administrator, Environmental Protection Agency, 
Room 3000, William Jefferson Clinton Building, 1200 Pennsylvania Ave. 
NW, Washington, DC 20460, with an electronic copy to the person listed 
in FOR FURTHER INFORMATION CONTACT, and the Associate General Counsel 
for the Air and Radiation Law Office, Office of General Counsel (Mail 
Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave. 
NW, Washington, DC 20004. Note that under CAA section 307(b)(2), the 
requirements established by this final rule may not be challenged 
separately in any civil or criminal proceedings brought by the EPA to 
enforce these requirements.

List of Subjects

40 CFR Part 9

    Environmental protection, Administrative practice and procedure, 
Reporting and recordkeeping requirements.

40 CFR Part 98

    Environmental protection, Greenhouse gases, Incorporation by 
reference, Reporting and recordkeeping requirements, Suppliers.

Michael S. Regan,
Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency amends title 40, chapter I, of the Code of Federal 
Regulations as follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

0
1. The authority citation for part 9 continues to read as follows:

    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003, 
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 31 U.S.C. 9701; 33 
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330, 
1342, 1344, 1345(d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 
1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 
300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 
300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542, 
9601-9657, 11023, 11048.


0
2. Amend Sec.  9.1 by adding an undesignated center heading and an 
entry for ``98.1-98.528'' in numerical order to read as follows:


Sec.  9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                                                            OMB control
                     40 CFR citation                            No.
------------------------------------------------------------------------
 
                                * * * * *
------------------------------------------------------------------------
                   Mandatory Greenhouse Gas Reporting
------------------------------------------------------------------------
98.1-98.528.............................................       2060-0629
 
                                * * * * *
------------------------------------------------------------------------

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
3. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

Subpart A--General Provision

0
4. Amend Sec.  98.2 by:
0
a. Revising paragraphs (f)(1) and (i)(1) and (2); and
0
b. Adding paragraph (k).
    The revisions and addition read as follows:


Sec.  98.2   Who must report?

* * * * *
    (f) * * *
    (1) Calculate the mass in metric tons per year of CO2, 
N2O, each fluorinated GHG, and each fluorinated heat 
transfer fluid that is imported and the mass in metric tons per year of 
CO2, N2O, each fluorinated GHG, and each 
fluorinated heat transfer fluid that is exported during the year.
* * * * *
    (i) * * *
    (1) If reported CO2e emissions, calculated in accordance 
with Sec.  98.3(c)(4)(i), are less than 25,000 metric tons per year for 
five consecutive years, then the owner or operator may discontinue 
complying with this part provided that the owner or operator submits a 
notification to the Administrator that announces the cessation of 
reporting and explains the reasons for the reduction in emissions. The 
notification shall be submitted no later than March 31 of the year 
immediately following the fifth consecutive year of emissions less than 
25,000 tons CO2e per year. The owner or operator must 
maintain the corresponding records required under Sec.  98.3(g) for 
each of the five consecutive years prior to notification of 
discontinuation of reporting and retain such records for three years 
following the year that reporting was discontinued. The owner or 
operator must resume reporting if annual CO2e emissions, 
calculated in accordance with paragraph (b)(4) of this section, in any 
future calendar year increase to 25,000 metric tons per year or more.
    (2) If reported CO2e emissions, calculated in accordance 
with Sec.  98.3(c)(4)(i), were less than 15,000 metric tons per year 
for three consecutive years, then the owner or operator may discontinue 
complying with this part provided that the owner or operator submits a 
notification to the Administrator that announces the cessation of 
reporting and explains the reasons for the reduction in emissions. The 
notification shall be submitted no later than March 31 of the year 
immediately following the third consecutive year of emissions less than 
15,000 tons CO2e per year. The owner or operator must 
maintain the corresponding records required under Sec.  98.3(g) for 
each of the three consecutive years and retain such records for three 
years prior to notification of discontinuation of reporting following 
the year that reporting was discontinued. The owner

[[Page 31890]]

or operator must resume reporting if annual CO2e emissions, 
calculated in accordance with paragraph (b)(4) of this section, in any 
future calendar year increase to 25,000 metric tons per year or more.
* * * * *
    (k) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold under paragraph (a)(4) of this 
section for facilities that destroy fluorinated GHGs or fluorinated 
heat transfer fluids, the owner or operator shall calculate the mass in 
metric tons per year of CO2e destroyed as described in 
paragraphs (k)(1) through (3) of this section.
    (1) Calculate the mass in metric tons per year of each fluorinated 
GHG or fluorinated heat transfer fluid that is destroyed during the 
year.
    (2) Convert the mass of each destroyed fluorinated GHG or 
fluorinated heat transfer fluid from paragraph (k)(1) of this section 
to metric tons of CO2e using equation A-1 to this section.
    (3) Sum the total annual metric tons of CO2e in 
paragraph (k)(2) of this section for all destroyed fluorinated GHGs and 
destroyed fluorinated heat transfer fluids.

0
5. Amend Sec.  98.3 by:
0
a. Revising paragraphs (b)(2), (h)(4), and (k)(1) through (3); and
0
b. Revising and republishing paragraph (l).
    The revisions and republication read as follows:


Sec.  98.3  What are the general monitoring, reporting, recordkeeping 
and verification requirements of this part?

* * * * *
    (b) * * *
    (2) For a new facility or supplier that begins operation on or 
after January 1, 2010 and becomes subject to the rule in the year that 
it becomes operational, report emissions starting the first operating 
month and ending on December 31 of that year. Each subsequent annual 
report must cover emissions for the calendar year, beginning on January 
1 and ending on December 31.
* * * * *
    (h) * * *
    (4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon 
request by the owner or operator, the Administrator may provide 
reasonable extensions of the 45-day period for submission of the 
revised report or information under paragraphs (h)(1) and (2) of this 
section. If the Administrator receives a request for extension of the 
45-day period, by email to an address prescribed by the Administrator 
prior to the expiration of the 45-day period, the extension request is 
deemed to be automatically granted for 30 days. The Administrator may 
grant an additional extension beyond the automatic 30-day extension if 
the owner or operator submits a request for an additional extension and 
the request is received by the Administrator prior to the expiration of 
the automatic 30-day extension, provided the request demonstrates that 
it is not practicable to submit a revised report or information under 
paragraphs (h)(1) and (2) of this section within 75 days. The 
Administrator will approve the extension request if the request 
demonstrates to the Administrator's satisfaction that it is not 
practicable to collect and process the data needed to resolve potential 
reporting errors identified pursuant to paragraph (h)(1) or (2) of this 
section within 75 days. The Administrator will only approve an 
extension request for a total of 180 days after the initial 
notification of a substantive error.
* * * * *
    (k) * * *
    (1) A facility or supplier that first becomes subject to part 98 
due to a change in the GWP for one or more compounds in table A-1 to 
this subpart, Global Warming Potentials, is not required to submit an 
annual GHG report for the reporting year during which the change in 
GWPs is published in the Federal Register as a final rulemaking.
    (2) A facility or supplier that was already subject to one or more 
subparts of this part but becomes subject to one or more additional 
subparts due to a change in the GWP for one or more compounds in table 
A-1 to this subpart, is not required to include those subparts to which 
the facility is subject only due to the change in the GWP in the annual 
GHG report submitted for the reporting year during which the change in 
GWPs is published in the Federal Register as a final rulemaking.
    (3) Starting on January 1 of the year after the year during which 
the change in GWPs is published in the Federal Register as a final 
rulemaking, facilities or suppliers identified in paragraph (k)(1) or 
(2) of this section must start monitoring and collecting GHG data in 
compliance with the applicable subparts of part 98 to which the 
facility is subject due to the change in the GWP for the annual 
greenhouse gas report for that reporting year, which is due by March 31 
of the following calendar year.
* * * * *
    (l) Special provision for best available monitoring methods in 2014 
and subsequent years. This paragraph (l) applies to owners or operators 
of facilities or suppliers that first become subject to any subpart of 
this part due to an amendment to table A-1 to this subpart, Global 
Warming Potentials.
    (1) Best available monitoring methods. From January 1 to March 31 
of the year after the year during which the change in GWPs is published 
in the Federal Register as a final rulemaking, owners or operators 
subject to this paragraph (l) may use best available monitoring methods 
for any parameter (e.g., fuel use, feedstock rates) that cannot 
reasonably be measured according to the monitoring and QA/QC 
requirements of a relevant subpart. The owner or operator must use the 
calculation methodologies and equations in the ``Calculating GHG 
Emissions'' sections of each relevant subpart, but may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by January 1 of the year after the year during 
which the change in GWPs is published in the Federal Register as a 
final rulemaking. Starting no later than April 1 of the year after the 
year during which the change in GWPs is published, the owner or 
operator must discontinue using best available methods and begin 
following all applicable monitoring and QA/QC requirements of this 
part, except as provided in paragraph (l)(2) of this section. Best 
available monitoring methods means any of the following methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of a relevant subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Requests for extension of the use of best available monitoring 
methods. The owner or operator may submit a request to the 
Administrator to use one or more best available monitoring methods 
beyond March 31 of the year after the year during which the change in 
GWPs is published in the Federal Register as a final rulemaking.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than January 31 of the year after the year during which 
the change in GWPs is published in the Federal Register as a final 
rulemaking.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific items of monitoring instrumentation for 
which the request is being made and the locations where each piece of

[[Page 31891]]

monitoring instrumentation will be installed.
    (B) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) for which the instrumentation 
is needed.
    (C) A description of the reasons that the needed equipment could 
not be obtained and installed before April 1 of the year after the year 
during which the change in GWPs is published in the Federal Register as 
a final rulemaking.
    (D) If the reason for the extension is that the equipment cannot be 
purchased and delivered by April 1 of the year after the year during 
which the change in GWPs is published in the Federal Register as a 
final rulemaking, include supporting documentation such as the date the 
monitoring equipment was ordered, investigation of alternative 
suppliers and the dates by which alternative vendors promised delivery, 
backorder notices or unexpected delays, descriptions of actions taken 
to expedite delivery, and the current expected date of delivery.
    (E) If the reason for the extension is that the equipment cannot be 
installed without a process unit shutdown, include supporting 
documentation demonstrating that it is not practicable to isolate the 
equipment and install the monitoring instrument without a full process 
unit shutdown. Include the date of the most recent process unit 
shutdown, the frequency of shutdowns for this process unit, and the 
date of the next planned shutdown during which the monitoring equipment 
can be installed. If there has been a shutdown or if there is a planned 
process unit shutdown between November 29 of the year during which the 
change in GWPs is published in the Federal Register as a final 
rulemaking and April 1 of the year after the year during which the 
change in GWPs is published, include a justification of why the 
equipment could not be obtained and installed during that shutdown.
    (F) A description of the specific actions the facility will take to 
obtain and install the equipment as soon as reasonably feasible and the 
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by April 1 of the year after the year during 
which the change in GWPs is published in the Federal Register as a 
final rulemaking. The use of best available methods under this 
paragraph (l) will not be approved beyond December 31 of the year after 
the year during which the change in GWPs is published.

0
6. Amend Sec.  98.5 by revising paragraph (b) to read as follows:


Sec.  98.5  How is the report submitted?

* * * * *
    (b) For reporting year 2014 and thereafter, unless a later year is 
specified in the applicable recordkeeping section, you must enter into 
verification software specified by the Administrator the data specified 
as verification software records in each applicable recordkeeping 
section. For each data element entered into the verification software, 
if the software produces a warning message for the data value and you 
elect not to revise the data value, you may provide an explanation in 
the verification software of why the data value is not being revised.

0
7. Amend Sec.  98.6 by:
0
a. Revising the definitions ``ASTM'', ``Bulk'', and ``Carbon dioxide 
stream'';
0
b. Adding the definitions ``Cyclic'' and ``Direct air capture (DAC)'' 
in alphabetical order;
0
c. Removing the definition ``Fluorinated greenhouse gas'';
0
d. Adding the definition ``Fluorinated greenhouse gas (GHG)'' in 
alphabetical order;
0
e. Revising the definition ``Fluorinated greenhouse gas (GHG) group'';
0
f. Adding the definition ``Fluorinated heat transfer fluids'' in 
alphabetic order;
0
g. Revising the definition ``Greenhouse gas or GHG'';
0
h. Removing the definition ``Other fluorinated GHGs'';
0
i. Revising the definition ``Process vent''; and
0
j. Adding definitions ``Remaining fluorinated GHGs'', ``Saturated 
chlorofluorocarbons (CFCs)'', ``Unsaturated bromochlorofluorocarbons 
(BCFCs)'', ``Unsaturated bromofluorocarbons (BFCs)'', ``Unsaturated 
chlorofluorocarbons (CFCs)'', ``Unsaturated 
hydrobromochlorofluorocarbons (HBCFCs)'', and ``Unsaturated 
hydrobromofluorocarbons (HBFCs)'' in alphabetic order.
    The revisions and additions read as follows:


Sec.  98.6   Definitions.

* * * * *
    ASTM means ASTM, International.
* * * * *
    Bulk, with respect to industrial GHG suppliers and CO2 
suppliers, means a transfer of gas in any amount that is in a container 
for the transportation or storage of that substance such as cylinders, 
drums, ISO tanks, and small cans. An industrial gas or CO2 
that must first be transferred from a container to another container, 
vessel, or piece of equipment in order to realize its intended use is a 
bulk substance. An industrial GHG or CO2 that is contained 
in a manufactured product such as electrical equipment, appliances, 
aerosol cans, or foams is not a bulk substance.
* * * * *
    Carbon dioxide stream means carbon dioxide that has been captured 
from an emission source (e.g., a power plant or other industrial 
facility), captured from ambient air (e.g., direct air capture), or 
extracted from a carbon dioxide production well plus incidental 
associated substances either derived from the source materials and the 
capture process or extracted with the carbon dioxide.
* * * * *
    Cyclic, in the context of fluorinated GHGs, means a fluorinated GHG 
in which three or more carbon atoms are connected to form a ring.
* * * * *
    Direct air capture (DAC), with respect to a facility, technology, 
or system, means that the facility, technology, or system uses carbon 
capture equipment to capture carbon dioxide directly from the air. 
Direct air capture does not include any facility, technology, or system 
that captures carbon dioxide:
    (1) That is deliberately released from a naturally occurring 
subsurface spring; or
    (2) Using natural photosynthesis.
* * * * *
    Fluorinated greenhouse gas (GHG) means sulfur hexafluoride 
(SF6), nitrogen trifluoride (NF3), and any fluorocarbon 
except for controlled substances as defined at part 82, subpart A of 
this subchapter and substances with vapor pressures of less than 1 mm 
of Hg absolute at 25 degrees C. With these exceptions, ``fluorinated 
GHG'' includes but is not limited to any hydrofluorocarbon, any 
perfluorocarbon, any fully fluorinated linear, branched or cyclic 
alkane, ether, tertiary amine or aminoether, any perfluoropolyether, 
and any hydrofluoropolyether.
    Fluorinated greenhouse gas (GHG) group means one of the following 
sets of fluorinated GHGs:
    (1) Fully fluorinated GHGs;
    (2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen 
bonds;
    (3) Saturated hydrofluorocarbons with three or more carbon-hydrogen 
bonds;

[[Page 31892]]

    (4) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
one carbon-hydrogen bond;
    (5) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
two carbon-hydrogen bonds;
    (6) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
three or more carbon-hydrogen bonds;
    (7) Saturated chlorofluorocarbons (CFCs);
    (8) Fluorinated formates;
    (9) Cyclic forms of the following: unsaturated perfluorocarbons 
(PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated 
hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons 
(BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated 
hydrobromofluorocarbons (HBFCs), unsaturated 
hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, 
and unsaturated halogenated esters;
    (10) Fluorinated acetates, carbonofluoridates, and fluorinated 
alcohols other than fluorotelomer alcohols;
    (11) Fluorinated aldehydes, fluorinated ketones and non-cyclic 
forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated 
CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, 
unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers, 
and unsaturated halogenated esters;
    (12) Fluorotelomer alcohols;
    (13) Fluorinated GHGs with carbon-iodine bonds; or
    (14) Remaining fluorinated GHGs.
    Fluorinated heat transfer fluids means fluorinated GHGs used for 
temperature control, device testing, cleaning substrate surfaces and 
other parts, other solvent applications, and soldering in certain types 
of electronics manufacturing production processes and in other 
industries. Fluorinated heat transfer fluids do not include fluorinated 
GHGs used as lubricants or surfactants in electronics manufacturing. 
For fluorinated heat transfer fluids, the lower vapor pressure limit of 
1 mm Hg in absolute at 25 [deg]C in the definition of ``fluorinated 
greenhouse gas'' in this section shall not apply. Fluorinated heat 
transfer fluids include, but are not limited to, perfluoropolyethers 
(including PFPMIE), perfluoroalkylamines, perfluoroalkylmorpholines, 
perfluoroalkanes, perfluoroethers, perfluorocyclic ethers, and 
hydrofluoroethers. Fluorinated heat transfer fluids include HFC-43-
10meee but do not include other hydrofluorocarbons.
* * * * *
    Greenhouse gas or GHG means carbon dioxide (CO2), 
methane (CH4), nitrous oxide (N2O), and 
fluorinated greenhouse gases (GHGs) as defined in this section.
* * * * *
    Process vent means a gas stream that: Is discharged through a 
conveyance to the atmosphere either directly or after passing through a 
control device; originates from a unit operation, including but not 
limited to reactors (including reformers, crackers, and furnaces, and 
separation equipment for products and recovered byproducts); and 
contains or has the potential to contain GHG that is generated in the 
process. Process vent does not include safety device discharges, 
equipment leaks, gas streams routed to a fuel gas system or to a flare, 
discharges from storage tanks.
* * * * *
    Remaining fluorinated GHGs means fluorinated GHGs that are none of 
the following:
    (1) Fully fluorinated GHGs;
    (2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen 
bonds;
    (3) Saturated hydrofluorocarbons with three or more carbon-hydrogen 
bonds;
    (4) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
one carbon-hydrogen bond;
    (5) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
two carbon-hydrogen bonds;
    (6) Saturated hydrofluoroethers and hydrochlorofluoroethers with 
three or more carbon-hydrogen bonds;
    (7) Saturated chlorofluorocarbons (CFCs);
    (8) Fluorinated formates;
    (9) Cyclic forms of the following: unsaturated perfluorocarbons 
(PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated 
hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons 
(BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated 
hydrobromofluorocarbons (HBFCs), unsaturated 
hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, 
and unsaturated halogenated esters;
    (10) Fluorinated acetates, carbonofluoridates, and fluorinated 
alcohols other than fluorotelomer alcohols;
    (11) Fluorinated aldehydes, fluorinated ketones and non-cyclic 
forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated 
CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, 
unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers, 
and unsaturated halogenated esters;
    (12) Fluorotelomer alcohols; or
    (13) fluorinated GHGs with carbon-iodine bonds.
* * * * *
    Saturated chlorofluorocarbons (CFCs) means fluorinated GHGs that 
contain only chlorine, fluorine, and carbon and that contain only 
single bonds.
* * * * *
    Unsaturated bromochlorofluoro-carbons (BCFCs) means fluorinated 
GHGs that contain only bromine, chlorine, fluorine, and carbon and that 
contain one or more bonds that are not single bonds.
    Unsaturated bromofluorocarbons (BFCs) means fluorinated GHGs that 
contain only bromine, fluorine, and carbon and that contain one or more 
bonds that are not single bonds.
    Unsaturated chlorofluorocarbons (CFCs) means fluorinated GHGs that 
contain only chlorine, fluorine, and carbon and that contain one or 
more bonds that are not single bonds.
* * * * *
    Unsaturated hydrobromochloro-fluorocarbons (HBCFCs) means 
fluorinated GHGs that contain only hydrogen, bromine, chlorine, 
fluorine, and carbon and that contain one or more bonds that are not 
single bonds.
    Unsaturated hydrobromofluoro-carbons (HBFCs) means fluorinated GHGs 
that contain only hydrogen, bromine, fluorine, and carbon and that 
contain one or more bonds that are not single bonds.
* * * * *

0
8. Amend Sec.  98.7 by:
0
a. Revising the introductory text;
0
b. Redesignating paragraphs (c) through (e) as paragraphs (b) through 
(d);
0
c. Revising newly redesignated paragraph (d);
0
d. Adding new paragraph (e); and
0
e. Revising paragraphs (i) and (m)(3).
    The revisions and addition read as follows:


Sec.  98.7   What standardized methods are incorporated by reference 
into this part?

    Certain material is incorporated by reference into this part with 
the approval of the Director of the Federal Register under 5 U.S.C. 
552(a) and 1 CFR part 51. To enforce any edition other than that 
specified in this section, the EPA must publish a document in the 
Federal Register and the material must be available to the public. All 
approved incorporation by reference (IBR) material is available for 
inspection at the EPA and at the National Archives

[[Page 31893]]

and Records Administration (NARA). Contact EPA at: EPA Docket Center, 
Public Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. 
NW, Washington, DC; phone: 202-566-1744; email: [email protected]; website: www.epa.gov/dockets/epa-docket-center-reading-room. For information on the availability of this 
material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email [email protected]. The material may be obtained 
from the following sources:
* * * * *
    (d) ASTM International (ASTM), 100 Barr Harbor Drive, P.O. Box 
CB700, West Conshohocken, Pennsylvania 19428-B2959; (800) 262-1373; 
www.astm.org.
    (1) ASTM C25-06, Standard Test Method for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime, approved February 15, 2006; 
IBR approved for Sec. Sec.  98.114(b); 98.174(b); 98.184(b); 98.194(c); 
98.334(b); and 98.504(b).
    (2) ASTM C114-09, Standard Test Methods for Chemical Analysis of 
Hydraulic Cement; IBR approved for Sec.  98.84(a) through (c).
    (3) ASTM D235-02 (Reapproved 2007), Standard Specification for 
Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent); 
IBR approved for Sec.  98.6.
    (4) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat 
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter; IBR 
approved for Sec.  98.254(e).
    (5) ASTM D388-05, Standard Classification of Coals by Rank; IBR 
approved for Sec.  98.6.
    (6) ASTM D910-07a, Standard Specification for Aviation Gasolines; 
IBR approved for Sec.  98.6.
    (7) ASTM D1826-94 (Reapproved 2003), Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter; IBR approved for Sec.  98.254(e).
    (8) ASTM D1836-07, Standard Specification for Commercial Hexanes; 
IBR approved for Sec.  98.6.
    (9) ASTM D1941-91 (Reapproved 2007), Standard Test Method for Open 
Channel Flow Measurement of Water with the Parshall Flume, approved 
June 15, 2007; IBR approved for Sec.  98.354(d).
    (10) ASTM D1945-03, Standard Test Method for Analysis of Natural 
Gas by Gas Chromatography; IBR approved for Sec. Sec.  98.74(c); 
98.164(b); 98.244(b); 98.254(d); 98.324(d); 98.344(b); 98.354(g).
    (11) ASTM D1946-90 (Reapproved 2006), Standard Practice for 
Analysis of Reformed Gas by Gas Chromatography; IBR approved for 
Sec. Sec.  98.74(c); 98.164(b); 98.254(d); 98.324(d); 98.344(b); 
98.354(g); 98.364(c).
    (12) ASTM D2013-07, Standard Practice for Preparing Coal Samples 
for Analysis; IBR approved for Sec.  98.164(b).
    (13) ASTM D2234/D2234M-07, Standard Practice for Collection of a 
Gross Sample of Coal; IBR approved for Sec.  98.164(b).
    (14) ASTM D2502-04, Standard Test Method for Estimation of Mean 
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements; 
IBR approved for Sec.  98.74(c).
    (15) ASTM D2503-92 (Reapproved 2007), Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure; IBR approved for 
Sec. Sec.  98.74(c); 98.254(d)(6).
    (16) ASTM D2505-88 (Reapproved 2004)e1, Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity 
Ethylene by Gas Chromatography; IBR approved for Sec.  98.244(b).
    (17) ASTM D2593-93 (Reapproved 2009), Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, 
approved July 1, 2009; IBR approved for Sec.  98.244(b).
    (18) ASTM D2597-94 (Reapproved 2004), Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing 
Nitrogen and Carbon Dioxide by Gas Chromatography; IBR approved for 
Sec.  98.164(b).
    (19) ASTM D2879-97 (Reapproved 2007), Standard Test Method for 
Vapor Pressure-Temperature Relationship and Initial Decomposition 
Temperature of Liquids by Isoteniscope (ASTM D2879), approved May 1, 
2007; IBR approved for Sec.  98.128.
    (20) ASTM D3176-15, Standard Practice for Ultimate Analysis of Coal 
and Coke, approved January 1, 2015; IBR approved for Sec.  98.494(c).
    (21) ASTM D3176-89 (Reapproved 2002), Standard Practice for 
Ultimate Analysis of Coal and Coke; IBR approved for Sec. Sec.  
98.74(c); 98.164(b); 98.244(b); 98.284(c) and (d); 98.314(c), (d), and 
(f).
    (22) ASTM D3238-95 (Reapproved 2005), Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method; IBR approved for Sec. Sec.  
98.74(c); 98.164(b).
    (23) ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels; IBR approved for Sec.  98.254(e).
    (24) ASTM D3682-01 (Reapproved 2006), Standard Test Method for 
Major and Minor Elements in Combustion Residues from Coal Utilization 
Processes; IBR approved for Sec.  98.144(b).
    (25) ASTM D4057-06, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products; IBR approved for Sec.  98.164(b).
    (26) ASTM D4177-95 (Reapproved 2005), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products; IBR approved 
for Sec.  98.164(b).
    (27) ASTM D4809-06, Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method); IBR 
approved for Sec.  98.254(e).
    (28) ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion; IBR approved for Sec. Sec.  98.254(e); 98.324(d).
    (29) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants; IBR approved for Sec. Sec.  
98.74(c); 98.164(b); 98.244(b).
    (30) ASTM D5291-16, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products 
and Lubricants, approved October 1, 2016; IBR approved for Sec.  
98.494(c).
    (31) ASTM D5373-08, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal, approved February 1, 2008; IBR approved for Sec. Sec.  
98.74(c); 98.114(b); 98.164(b); 98.174(b); 98.184(b); 98.244(b); 
98.274(b); 98.284(c) and (d); 98.314(c), (d), and (f); 98.334(b); 
98.504(b).
    (32) ASTM D5373-21, Standard Test Methods for Determination of 
Carbon, Hydrogen, and Nitrogen in Analysis Samples of Coal and Carbon 
in Analysis Samples of Coal and Coke, approved April 1, 2021; IBR 
approved for Sec.  98.494(c).
    (33) ASTM D5614-94 (Reapproved 2008), Standard Test Method for Open 
Channel Flow Measurement of Water with Broad-Crested Weirs, approved 
October 1, 2008; IBR approved for Sec.  98.354(d).
    (34) ASTM D6060-96 (Reapproved 2001), Standard Practice for 
Sampling of Process Vents With a Portable Gas Chromatograph; IBR 
approved for Sec.  98.244(b).
    (35) ASTM D6348-03, Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared

[[Page 31894]]

(FTIR) Spectroscopy; IBR approved for Sec.  98.54(b); table I-9 to 
subpart I of this part; Sec. Sec.  98.224(b); 98.414(n).
    (36) ASTM D6349-09, Standard Test Method for Determination of Major 
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of 
Coal and Coke by Inductively Coupled Plasma--Atomic Emission 
Spectrometry; IBR approved for Sec.  98.144(b).
    (37) ASTM D6609-08, Standard Guide for Part-Stream Sampling of 
Coal; IBR approved for Sec.  98.164(b).
    (38) ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels; IBR approved for Sec.  98.6.
    (39) ASTM D6866-16, Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using 
Radiocarbon Analysis, approved June 1, 2016; IBR approved for 
Sec. Sec.  98.34(d) and (e); 98.36(e).
    (40) ASTM D6883-04, Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles; IBR 
approved for Sec.  98.164(b).
    (41) ASTM D7359-08, Standard Test Method for Total Fluorine, 
Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by 
Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography 
Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved 
October 15, 2008; IBR approved for Sec.  98.124(e)(2).
    (42) ASTM D7430-08ae1, Standard Practice for Mechanical Sampling of 
Coal; IBR approved for Sec.  98.164(b).
    (43) ASTM D7459-08, Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources; IBR approved 
for Sec. Sec.  98.34(d) and (e); 98.36(e).
    (44) ASTM D7633-10, Standard Test Method for Carbon Black--Carbon 
Content, approved May 15, 2010; IBR approved for Sec.  98.244(b).
    (45) ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for 
Analysis of Soda Ash (Sodium Carbonate); IBR approved for Sec.  
98.294(a) and (b).
    (46) ASTM E415-17, Standard Test Method for Analysis of Carbon and 
Low-Alloy Steel by Spark Atomic Emission Spectrometry, approved May 15, 
2017; IBR approved for Sec.  98.174(b).
    (47) ASTM E1019-08, Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques; IBR approved for 
Sec.  98.174(b).
    (48) ASTM E1915-07a, Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry; IBR approved for Sec.  98.174(b).
    (49) ASTM E1941-04, Standard Test Method for Determination of 
Carbon in Refractory and Reactive Metals and Their Alloys; IBR approved 
for Sec. Sec.  98.114(b); 98.184(b); 98.334(b).
    (50) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography; 
IBR approved for Sec. Sec.  98.164(b); 98.244(b); 98.254(d); 98.324(d); 
98.344(b); 98.354(g).
    (e) CSA Group (CSA), 178 Rexdale Boulevard, Toronto, Ontario Canada 
M9W 183; (800) 463-6727; https://shop.csa.ca.
    (1) CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation 
and geological storage--Carbon dioxide storage using enhanced oil 
recovery (CO2-EOR), approved August 30, 2019; IBR approved 
for Sec. Sec.  98.470(c); 98.480(a); 98.481(a) through (c); 98.482; 
98.483; 98.484; 98.485; 98.486(g); 98.487; 98.488(a)(5); 98.489.

    Note 1 to paragraph (e)(1):  This standard is also available 
from ISO as ISO 27916:2019(E).

    (2) [Reserved]
* * * * *
    (i) National Institute of Standards and Technology (NIST), 100 
Bureau Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, 
www.nist.gov/.
    (1) NIST HB 44-2023: Specifications, Tolerances, and Other 
Technical Requirements For Weighing and Measuring Devices, 2023 
edition, approved November 18, 2022; IBR approved for Sec.  98.494(b).
    (2) Specifications, Tolerances, and Other Technical Requirements 
For Weighing and Measuring Devices, NIST Handbook 44 (2009); IBR 
approved for Sec. Sec.  98.244(b); 98.344(a).
* * * * *
    (m) * * *
    (3) Protocol for Measuring Destruction or Removal Efficiency (DRE) 
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-
003), approved March 2010; IBR approved for Sec. Sec.  98.94(e); 
98.94(f) and (g); 98.97(b) and (d); 98.98; appendix A to subpart I of 
this part; Sec. Sec.  98.124(e); 98.414(n). (Also available from: 
www.epa.gov/sites/default/files/2016-02/documents/dre_protocol.pdf.)
* * * * *

0
9. Revise table A-1 to subpart A to read as follows:

               Table A-1 to Subpart A of Part 98--Global Warming Potentials, 100-Year Time Horizon
----------------------------------------------------------------------------------------------------------------
                                                                                                      Global
                                                                                                      warming
                    Name                           CAS No.               Chemical formula            potential
                                                                                                     (100 yr.)
----------------------------------------------------------------------------------------------------------------
                                             Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Carbon dioxide..............................           124-38-9  CO2............................               1
Methane.....................................            74-82-8  CH4............................      \a\ \d\ 28
Nitrous oxide...............................         10024-97-2  N2O............................     \a\ \d\ 265
----------------------------------------------------------------------------------------------------------------
                                             Fully Fluorinated GHGs
----------------------------------------------------------------------------------------------------------------
Sulfur hexafluoride.........................          2551-62-4  SF6............................  \a\ \d\ 23,500
Trifluoromethyl sulphur pentafluoride.......           373-80-8  SF5CF3.........................      \d\ 17,400
Nitrogen trifluoride........................          7783-54-2  NF3............................      \d\ 16,100
PFC-14 (Perfluoromethane)...................            75-73-0  CF4............................   \a\ \d\ 6,630
PFC-116 (Perfluoroethane)...................            76-16-4  C2F6...........................  \a\ \d\ 11,100
PFC-218 (Perfluoropropane)..................            76-19-7  C3F8...........................   \a\ \d\ 8,900
Perfluorocyclopropane.......................           931-91-9  c-C3F6.........................       \d\ 9,200
PFC-3-1-10 (Perfluorobutane)................           355-25-9  C4F10..........................   \a\ \d\ 9,200
PFC-318 (Perfluorocyclobutane)..............           115-25-3  c-C4F8.........................   \a\ \d\ 9,540

[[Page 31895]]

 
Perfluorotetrahydrofuran....................           773-14-8  c-C4F8O........................      \e\ 13,900
PFC-4-1-12 (Perfluoropentane)...............           678-26-2  C5F12..........................   \a\ \d\ 8,550
PFC-5-1-14 (Perfluorohexane, FC-72).........           355-42-0  C6F14..........................   \a\ \d\ 7,910
PFC-6-1-12..................................           335-57-9  C7F16; CF3(CF2)5CF3............       \b\ 7,820
PFC-7-1-18..................................           307-34-6  C8F18; CF3(CF2)6CF3............       \b\ 7,620
PFC-9-1-18..................................           306-94-5  C10F18.........................       \d\ 7,190
PFPMIE (HT-70)..............................                 NA  CF3OCF(CF3)CF2OCF2OCF3.........       \d\ 9,710
Perfluorodecalin (cis)......................         60433-11-6  Z-C10F18.......................   \b\ \d\ 7,240
Perfluorodecalin (trans)....................         60433-12-7  E-C10F18.......................   \b\ \d\ 6,290
Perfluorotriethylamine......................           359-70-6  N(C2F5)3.......................      \e\ 10,300
Perfluorotripropylamine.....................           338-83-0  N(CF2CF2CF3)3..................       \e\ 9,030
Perfluorotributylamine......................           311-89-7  N(CF2CF2CF2CF3)3...............       \e\ 8,490
Perfluorotripentylamine.....................           338-84-1  N(CF2CF2CF2CF2CF3)3............       \e\ 7,260
----------------------------------------------------------------------------------------------------------------
                   Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
(4s,5s)-1,1,2,2,3,3,4,5-                            158389-18-5  trans-cyc (-CF2CF2CF2CHFCHF-)..         \e\ 258
 octafluorocyclopentane.
HFC-23......................................            75-46-7  CHF3...........................  \a\ \d\ 12,400
HFC-32......................................            75-10-5  CH2F2..........................     \a\ \d\ 677
HFC-125.....................................           354-33-6  C2HF5..........................   \a\ \d\ 3,170
HFC-134.....................................           359-35-3  C2H2F4.........................   \a\ \d\ 1,120
HFC-134a....................................           811-97-2  CH2FCF3........................   \a\ \d\ 1,300
HFC-227ca...................................          2252-84-8  CF3CF2CHF2.....................       \b\ 2,640
HFC-227ea...................................           431-89-0  C3HF7..........................   \a\ \d\ 3,350
HFC-236cb...................................           677-56-5  CH2FCF2CF3.....................       \d\ 1,210
HFC-236ea...................................           431-63-0  CHF2CHFCF3.....................       \d\ 1,330
HFC-236fa...................................           690-39-1  C3H2F6.........................   \a\ \d\ 8,060
HFC-329p....................................           375-17-7  CHF2CF2CF2CF3..................        \b\ 2360
HFC-43-10mee................................        138495-42-8  CF3CFHCFHCF2CF3................   \a\ \d\ 1,650
----------------------------------------------------------------------------------------------------------------
                  Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
1,1,2,2,3,3-hexafluorocyclopentane..........        123768-18-3  cyc (-CF2CF2CF2CH2CH2-)........         \e\ 120
1,1,2,2,3,3,4-heptafluorocyclopentane.......         15290-77-4  cyc (-CF2CF2CF2CHFCH2-)........         \e\ 231
HFC-41......................................           593-53-3  CH3F...........................     \a\ \d\ 116
HFC-143.....................................           430-66-0  C2H3F3.........................     \a\ \d\ 328
HFC-143a....................................           420-46-2  C2H3F3.........................   \a\ \d\ 4,800
HFC-152.....................................           624-72-6  CH2FCH2F.......................          \d\ 16
HFC-152a....................................            75-37-6  CH3CHF2........................     \a\ \d\ 138
HFC-161.....................................           353-36-6  CH3CH2F........................           \d\ 4
HFC-245ca...................................           679-86-7  C3H3F5.........................     \a\ \d\ 716
HFC-245cb...................................          1814-88-6  CF3CF2CH3......................       \b\ 4,620
HFC-245ea...................................         24270-66-4  CHF2CHFCHF2....................         \b\ 235
HFC-245eb...................................           431-31-2  CH2FCHFCF3.....................         \b\ 290
HFC-245fa...................................           460-73-1  CHF2CH2CF3.....................         \d\ 858
HFC-263fb...................................           421-07-8  CH3CH2CF3......................          \b\ 76
HFC-272ca...................................           420-45-1  CH3CF2CH3......................         \b\ 144
HFC-365mfc..................................           406-58-6  CH3CF2CH2CF3...................         \d\ 804
----------------------------------------------------------------------------------------------------------------
      Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond
----------------------------------------------------------------------------------------------------------------
HFE-125.....................................          3822-68-2  CHF2OCF3.......................      \d\ 12,400
HFE-227ea...................................          2356-62-9  CF3CHFOCF3.....................       \d\ 6,450
HFE-329mcc2.................................        134769-21-4  CF3CF2OCF2CHF2.................       \d\ 3,070
HFE-329me3..................................        428454-68-6  CF3CFHCF2OCF3..................       \b\ 4,550
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-                 3330-15-2  CF3CF2CF2OCHFCF3...............       \b\ 6,490
 tetrafluoroethoxy)-propane.
----------------------------------------------------------------------------------------------------------------
                             Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-134 (HG-00).............................          1691-17-4  CHF2OCHF2......................       \d\ 5,560
HFE-236ca...................................         32778-11-3  CHF2OCF2CHF2...................       \b\ 4,240
HFE-236ca12 (HG-10).........................         78522-47-1  CHF2OCF2OCHF2..................       \d\ 5,350
HFE-236ea2 (Desflurane).....................         57041-67-5  CHF2OCHFCF3....................       \d\ 1,790
HFE-236fa...................................         20193-67-3  CF3CH2OCF3.....................         \d\ 979
HFE-338mcf2.................................        156053-88-2  CF3CF2OCH2CF3..................         \d\ 929
HFE-338mmz1.................................         26103-08-2  CHF2OCH(CF3)2..................       \d\ 2,620
HFE-338pcc13 (HG-01)........................        188690-78-0  CHF2OCF2CF2OCHF2...............       \d\ 2,910
HFE-43-10pccc (H-Galden 1040x, HG-11).......           E1730133  CHF2OCF2OC2F4OCHF2.............       \d\ 2,820
HCFE-235ca2 (Enflurane).....................         13838-16-9  CHF2OCF2CHFCl..................         \b\ 583

[[Page 31896]]

 
HCFE-235da2 (Isoflurane)....................         26675-46-7  CHF2OCHClCF3...................         \d\ 491
HG-02.......................................        205367-61-9  HF2C-(OCF2CF2)2-OCF2H..........   \b\ \d\ 2,730
HG-03.......................................        173350-37-3  HF2C-(OCF2CF2)3-OCF2H..........   \b\ \d\ 2,850
HG-20.......................................        249932-25-0  HF2C-(OCF2)2-OCF2H.............       \b\ 5,300
HG-21.......................................        249932-26-1  HF2C-OCF2CF2OCF2OCF2O-CF2H.....       \b\ 3,890
HG-30.......................................        188690-77-9  HF2C-(OCF2)3-OCF2H.............       \b\ 7,330
1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15        173350-38-4  HCF2O(CF2CF2O)4CF2H............       \b\ 3,630
 ,15-eicosafluoro-2,5,8,11,14-
 Pentaoxapentadecane.
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane.         84011-06-3  CHF2CHFOCF3....................       \b\ 1,240
Trifluoro(fluoromethoxy)methane.............          2261-01-0  CH2FOCF3.......................         \b\ 751
----------------------------------------------------------------------------------------------------------------
                        Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-143a....................................           421-14-7  CH3OCF3........................         \d\ 523
HFE-245cb2..................................         22410-44-2  CH3OCF2CF3.....................         \d\ 654
HFE-245fa1..................................         84011-15-4  CHF2CH2OCF3....................         \d\ 828
HFE-245fa2..................................          1885-48-9  CHF2OCH2CF3....................         \d\ 812
HFE-254cb1..................................           425-88-7  CH3OCF2CHF2....................         \d\ 301
HFE-263fb2..................................           460-43-5  CF3CH2OCH3.....................           \d\ 1
HFE-263m1; R-E-143a.........................           690-22-2  CF3OCH2CH3.....................          \b\ 29
HFE-347mcc3 (HFE-7000)......................           375-03-1  CH3OCF2CF2CF3..................         \d\ 530
HFE-347mcf2.................................        171182-95-9  CF3CF2OCH2CHF2.................         \d\ 854
HFE-347mmy1.................................         22052-84-2  CH3OCF(CF3)2...................         \d\ 363
HFE-347mmz1 (Sevoflurane)...................         28523-86-6  (CF3)2CHOCH2F..................         \c\ 216
HFE-347pcf2.................................           406-78-0  CHF2CF2OCH2CF3.................         \d\ 889
HFE-356mec3.................................           382-34-3  CH3OCF2CHFCF3..................         \d\ 387
HFE-356mff2.................................           333-36-8  CF3CH2OCH2CF3..................          \b\ 17
HFE-356mmz1.................................         13171-18-1  (CF3)2CHOCH3...................          \d\ 14
HFE-356pcc3.................................        160620-20-2  CH3OCF2CF2CHF2.................         \d\ 413
HFE-356pcf2.................................         50807-77-7  CHF2CH2OCF2CHF2................         \d\ 719
HFE-356pcf3.................................         35042-99-0  CHF2OCH2CF2CHF2................         \d\ 446
HFE-365mcf2.................................         22052-81-9  CF3CF2OCH2CH3..................          \b\ 58
HFE-365mcf3.................................           378-16-5  CF3CF2CH2OCH3..................        \d\ 0.99
HFE-374pc2..................................           512-51-6  CH3CH2OCF2CHF2.................         \d\ 627
HFE-449s1 (HFE-7100) Chemical blend.........        163702-07-6  C4F9OCH3.......................         \d\ 421
                                                    163702-08-7  (CF3)2CFCF2OCH3................  ..............
HFE-569sf2 (HFE-7200) Chemical blend........        163702-05-4  C4F9OC2H5......................          \d\ 57
                                                    163702-06-5  (CF3)2CFCF2OC2H5...............  ..............
HFE-7300....................................        132182-92-4  (CF3)2CFCFOC2H5CF2CF2CF3.......         \e\ 405
HFE-7500....................................        297730-93-9  n-C3F7CFOC2H5CF(CF3)2..........          \e\ 13
HG'-01......................................         73287-23-7  CH3OCF2CF2OCH3.................         \b\ 222
HG'-02......................................        485399-46-0  CH3O(CF2CF2O)2CH3..............         \b\ 236
HG'-03......................................        485399-48-2  CH3O(CF2CF2O)3CH3..............         \b\ 221
Difluoro(methoxy)methane....................           359-15-9  CH3OCHF2.......................         \b\ 144
2-Chloro-1,1,2-trifluoro-1-methoxyethane....           425-87-6  CH3OCF2CHFCl...................         \b\ 122
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane...         22052-86-4  CF3CF2CF2OCH2CH3...............          \b\ 61
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-       920979-28-8  C12H5F19O2.....................          \b\ 56
 bis[1,2,2,2-tetrafluoro-1-
 (trifluoromethyl)ethyl]-furan.
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane......           380-34-7  CF3CHFCF2OCH2CH3...............          \b\ 23
Fluoro(methoxy)methane......................           460-22-0  CH3OCH2F.......................          \b\ 13
1,1,2,2-Tetrafluoro-3-methoxy-propane;               60598-17-6  CHF2CF2CH2OCH3.................    \b\ \d\ 0.49
 Methyl 2,2,3,3-tetrafluoropropyl ether.
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane.         37031-31-5  CH2FOCF2CF2H...................         \b\ 871
Difluoro(fluoromethoxy)methane..............           461-63-2  CH2FOCHF2......................         \b\ 617
Fluoro(fluoromethoxy)methane................           462-51-1  CH2FOCH2F......................         \b\ 130
----------------------------------------------------------------------------------------------------------------
                                      Saturated Chlorofluorocarbons (CFCs)
----------------------------------------------------------------------------------------------------------------
E-R316c.....................................          3832-15-3  trans-cyc (-CClFCF2CF2CClF-)...       \e\ 4,230
Z-R316c.....................................          3934-26-7  cis-cyc (-CClFCF2CF2CClF-).....       \e\ 5,660
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Formates
----------------------------------------------------------------------------------------------------------------
Trifluoromethyl formate.....................         85358-65-2  HCOOCF3........................         \b\ 588
Perfluoroethyl formate......................        313064-40-3  HCOOCF2CF3.....................         \b\ 580
1,2,2,2-Tetrafluoroethyl formate............        481631-19-0  HCOOCHFCF3.....................         \b\ 470
Perfluorobutyl formate......................        197218-56-7  HCOOCF2CF2CF2CF3...............         \b\ 392
Perfluoropropyl formate.....................        271257-42-2  HCOOCF2CF2CF3..................         \b\ 376
1,1,1,3,3,3-Hexafluoropropan-2-yl formate...        856766-70-6  HCOOCH(CF3)2...................         \b\ 333
2,2,2-Trifluoroethyl formate................         32042-38-9  HCOOCH2CF3.....................          \b\ 33

[[Page 31897]]

 
3,3,3-Trifluoropropyl formate...............       1344118-09-7  HCOOCH2CH2CF3..................          \b\ 17
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Acetates
----------------------------------------------------------------------------------------------------------------
Methyl 2,2,2-trifluoroacetate...............           431-47-0  CF3COOCH3......................          \b\ 52
1,1-Difluoroethyl 2,2,2-trifluoroacetate....       1344118-13-3  CF3COOCF2CH3...................          \b\ 31
Difluoromethyl 2,2,2-trifluoroacetate.......          2024-86-4  CF3COOCHF2.....................          \b\ 27
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate.           407-38-5  CF3COOCH2CF3...................           \b\ 7
Methyl 2,2-difluoroacetate..................           433-53-4  HCF2COOCH3.....................           \b\ 3
Perfluoroethyl acetate......................        343269-97-6  CH3COOCF2CF3...................       \b\ \d\ 2
Trifluoromethyl acetate.....................         74123-20-9  CH3COOCF3......................       \b\ \d\ 2
Perfluoropropyl acetate.....................       1344118-10-0  CH3COOCF2CF2CF3................       \b\ \d\ 2
Perfluorobutyl acetate......................        209597-28-4  CH3COOCF2CF2CF2CF3.............       \b\ \d\ 2
Ethyl 2,2,2-trifluoroacetate................           383-63-1  CF3COOCH2CH3...................       \b\ \d\ 1
----------------------------------------------------------------------------------------------------------------
                                               Carbonofluoridates
----------------------------------------------------------------------------------------------------------------
Methyl carbonofluoridate....................          1538-06-3  FCOOCH3........................          \b\ 95
1,1-Difluoroethyl carbonofluoridate.........       1344118-11-1  FCOOCF2CH3.....................          \b\ 27
----------------------------------------------------------------------------------------------------------------
                             Fluorinated Alcohols Other Than Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
Bis(trifluoromethyl)-methanol...............           920-66-1  (CF3)2CHOH.....................         \d\ 182
2,2,3,3,4,4,5,5-Octafluorocyclopentanol.....         16621-87-7  cyc (-(CF2)4CH(OH)-)...........          \d\ 13
2,2,3,3,3-Pentafluoropropanol...............           422-05-9  CF3CF2CH2OH....................          \d\ 19
2,2,3,3,4,4,4-Heptafluorobutan-1-ol.........           375-01-9  C3F7CH2OH......................      \b\ \d\ 34
2,2,2-Trifluoroethanol......................            75-89-8  CF3CH2OH.......................          \b\ 20
2,2,3,4,4,4-Hexafluoro-1-butanol............           382-31-0  CF3CHFCF2CH2OH.................          \b\ 17
2,2,3,3-Tetrafluoro-1-propanol..............            76-37-9  CHF2CF2CH2OH...................          \b\ 13
2,2-Difluoroethanol.........................           359-13-7  CHF2CH2OH......................           \b\ 3
2-Fluoroethanol.............................           371-62-0  CH2FCH2OH......................         \b\ 1.1
4,4,4-Trifluorobutan-1-ol...................           461-18-7  CF3(CH2)2CH2OH.................        \b\ 0.05
----------------------------------------------------------------------------------------------------------------
                                 Non-Cyclic, Unsaturated Perfluorocarbons (PFCs)
----------------------------------------------------------------------------------------------------------------
PFC-1114; TFE...............................           116-14-3  CF2 = CF2; C2F4................       \b\ 0.004
PFC-1216; Dyneon HFP........................           116-15-4  C3F6; CF3CF = CF2..............        \b\ 0.05
Perfluorobut-2-ene..........................           360-89-4  CF3CF = CFCF3..................        \b\ 1.82
Perfluorobut-1-ene..........................           357-26-6  CF3CF2CF = CF2.................        \b\ 0.10
Perfluorobuta-1,3-diene.....................           685-63-2  CF2 = CFCF = CF2...............       \b\ 0.003
----------------------------------------------------------------------------------------------------------------
             Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
----------------------------------------------------------------------------------------------------------------
HFC-1132a; VF2..............................            75-38-7  C2H2F2, CF2 = CH2..............        \b\ 0.04
HFC-1141; VF................................            75-02-5  C2H3F, CH2 = CHF...............        \b\ 0.02
(E)-HFC-1225ye..............................          5595-10-8  CF3CF = CHF(E).................        \b\ 0.06
(Z)-HFC-1225ye..............................          5528-43-8  CF3CF = CHF(Z).................        \b\ 0.22
Solstice 1233zd(E)..........................        102687-65-0  C3H2ClF3; CHCl = CHCF3.........        \b\ 1.34
HCFO-1233zd(Z)..............................         99728-16-2  (Z)-CF3CH = CHCl...............        \e\ 0.45
HFC-1234yf; HFO-1234yf......................           754-12-1  C3H2F4; CF3CF = CH2............        \b\ 0.31
HFC-1234ze(E)...............................          1645-83-6  C3H2F4; trans-CF3CH = CHF......        \b\ 0.97
HFC-1234ze(Z)...............................         29118-25-0  C3H2F4; cis-CF3CH = CHF; CF3CH         \b\ 0.29
                                                                  = CHF.
HFC-1243zf; TFP.............................           677-21-4  C3H3F3, CF3CH = CH2............        \b\ 0.12
(Z)-HFC-1336................................           692-49-9  CF3CH = CHCF3(Z)...............        \b\ 1.58
HFO-1336mzz(E)..............................         66711-86-2  (E)-CF3CH = CHCF3..............          \e\ 18
HFC-1345zfc.................................           374-27-6  C2F5CH = CH2...................        \b\ 0.09
HFO-1123....................................           359-11-5  CHF=CF2........................       \e\ 0.005
HFO-1438ezy(E)..............................         14149-41-8  (E)-(CF3)2CFCH = CHF...........         \e\ 8.2
HFO-1447fz..................................           355-08-8  CF3(CF2)2CH = CH2..............        \e\ 0.24
Capstone 42-U...............................         19430-93-4  C6H3F9, CF3(CF2)3CH = CH2......        \b\ 0.16
Capstone 62-U...............................         25291-17-2  C8H3F13, CF3(CF2)5CH = CH2.....        \b\ 0.11
Capstone 82-U...............................         21652-58-4  C10H3F17, CF3(CF2)7CH = CH2....        \b\ 0.09
(e)-1-chloro-2-fluoroethene.................           460-16-2  (E)-CHCl = CHF.................       \e\ 0.004
3,3,3-trifluoro-2-(trifluoromethyl)prop-1-             382-10-5  (CF3)2C = CH2..................        \e\ 0.38
 ene.
----------------------------------------------------------------------------------------------------------------
                                          Non-Cyclic, Unsaturated CFCs
----------------------------------------------------------------------------------------------------------------
CFC-1112....................................           598-88-9  CClF=CClF......................        \e\ 0.13
CFC-1112a...................................            79-35-6  CCl2=CF2.......................       \e\ 0.021
----------------------------------------------------------------------------------------------------------------

[[Page 31898]]

 
                                   Non-Cyclic, Unsaturated Halogenated Ethers
----------------------------------------------------------------------------------------------------------------
PMVE; HFE-216...............................          1187-93-5  CF3OCF = CF2...................        \b\ 0.17
Fluoroxene..................................           406-90-6  CF3CH2OCH = CH2................        \b\ 0.05
Methyl-perfluoroheptene-ethers..............                N/A  CH3OC7F13......................          \e\ 15
----------------------------------------------------------------------------------------------------------------
                                   Non-Cyclic, Unsaturated Halogenated Esters
----------------------------------------------------------------------------------------------------------------
Ethenyl 2,2,2-trifluoroacetate..............           433-28-3  CF3COOCH=CH2...................       \e\ 0.008
Prop-2-enyl 2,2,2-trifluoroacetate..........           383-67-5  CF3COOCH2CH=CH2................       \e\ 0.007
----------------------------------------------------------------------------------------------------------------
                                        Cyclic, Unsaturated HFCs and PFCs
----------------------------------------------------------------------------------------------------------------
PFC C-1418..................................           559-40-0  c-C5F8.........................           \d\ 2
Hexafluorocyclobutene.......................           697-11-0  cyc (-CF=CFCF2CF2-)............         \e\ 126
1,3,3,4,4,5,5-heptafluorocyclopentene.......          1892-03-1  cyc (-CF2CF2CF2CF=CH-).........          \e\ 45
1,3,3,4,4-pentafluorocyclobutene............           374-31-2  cyc (-CH=CFCF2CF2-)............          \e\ 92
3,3,4,4-tetrafluorocyclobutene..............          2714-38-7  cyc (-CH=CHCF2CF2-)............          \e\ 26
----------------------------------------------------------------------------------------------------------------
                                              Fluorinated Aldehydes
----------------------------------------------------------------------------------------------------------------
3,3,3-Trifluoro-propanal....................           460-40-2  CF3CH2CHO......................        \b\ 0.01
----------------------------------------------------------------------------------------------------------------
                                               Fluorinated Ketones
----------------------------------------------------------------------------------------------------------------
Novec 1230 (perfluoro (2-methyl-3-                     756-13-8  CF3CF2C(O)CF (CF3)2............         \b\ 0.1
 pentanone)).
1,1,1-trifluoropropan-2-one.................           421-50-1  CF3COCH3.......................        \e\ 0.09
1,1,1-trifluorobutan-2-one..................           381-88-4  CF3COCH2CH3....................       \e\ 0.095
----------------------------------------------------------------------------------------------------------------
                                             Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-         185689-57-0  CF3(CF2)4CH2CH2OH..............        \b\ 0.43
 ol.
3,3,3-Trifluoropropan-1-ol..................          2240-88-2  CF3CH2CH2OH....................        \b\ 0.35
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-                         755-02-2  CF3(CF2)6CH2CH2OH..............        \b\ 0.33
 Pentadecafluorononan-1-ol.
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-          87017-97-8  CF3(CF2)8CH2CH2OH..............        \b\ 0.19
 Nonadecafluoroundecan-1-ol.
----------------------------------------------------------------------------------------------------------------
                                   Fluorinated GHGs With Carbon-Iodine Bond(s)
----------------------------------------------------------------------------------------------------------------
Trifluoroiodomethane........................          2314-97-8  CF3I...........................         \b\ 0.4
----------------------------------------------------------------------------------------------------------------
                             Remaining Fluorinated GHGs with Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Dibromodifluoromethane (Halon 1202).........            75-61-6  CBr2F2.........................         \b\ 231
2-Bromo-2-chloro-1,1,1-trifluoroethane                 151-67-7  CHBrClCF3......................          \b\ 41
 (Halon-2311/Halothane).
Heptafluoroisobutyronitrile.................         42532-60-5  (CF3)2CFCN.....................       \e\ 2,750
Carbonyl fluoride...........................           353-50-4  COF2...........................        \e\ 0.14
----------------------------------------------------------------------------------------------------------------


------------------------------------------------------------------------
                                                          Global warming
               Fluorinated GHG group \f\                 potential  (100
                                                               yr.)
------------------------------------------------------------------------
   Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not
                              Listed Above
------------------------------------------------------------------------
Fully fluorinated GHGs \g\.............................            9,200
Saturated hydrofluorocarbons (HFCs) with 2 or fewer                3,000
 carbon-hydrogen bonds \g\.............................
Saturated HFCs with 3 or more carbon-hydrogen bonds \g\              840
Saturated hydrofluoroethers (HFEs) and                             6,600
 hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen
 bond \g\..............................................
Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds              2,900
 \g\...................................................
Saturated HFEs and HCFEs with 3 or more carbon-hydrogen              320
 bonds \g\.............................................
Saturated chlorofluorocarbons (CFCs) \g\...............            4,900
Fluorinated formates...................................              350
Cyclic forms of the following: unsaturated                            58
 perfluorocarbons (PFCs), unsaturated HFCs, unsaturated
 CFCs, unsaturated hydrochlorofluorocarbons (HCFCs),
 unsaturated bromofluorocarbons (BFCs), unsaturated
 bromochlorofluorocarbons (BCFCs), unsaturated
 hydrobromofluorocarbons (HBFCs), unsaturated
 hydrobromochlorofluorocarbons (HBCFCs), unsaturated
 halogenated ethers, and unsaturated halogenated esters
 \g\...................................................
Fluorinated acetates, carbonofluoridates, and                         25
 fluorinated alcohols other than fluorotelomer alcohols
 \g\...................................................

[[Page 31899]]

 
Fluorinated aldehydes, fluorinated ketones, and non-                   1
 cyclic forms of the following: unsaturated
 perfluorocarbons (PFCs), unsaturated HFCs, unsaturated
 CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated
 BCFCs, unsaturated HBFCs, unsaturated HBCFCs,
 unsaturated halogenated ethers and unsaturated
 halogenated esters \g\................................
Fluorotelomer alcohols \g\.............................                1
Fluorinated GHGs with carbon-iodine bond(s) \g\........                1
Other fluorinated GHGs \g\.............................            1,800
------------------------------------------------------------------------
\a\ The GWP for this compound was updated in the final rule published on
  November 29, 2013 [78 FR 71904] and effective on January 1, 2014.
\b\ This compound was added to table A-1 in the final rule published on
  December 11, 2014, and effective on January 1, 2015.
\c\ The GWP for this compound was updated in the final rule published on
  December 11, 2014, and effective on January 1, 2015.
\d\ The GWP for this compound was updated in the final rule published on
  April 25, 2024 and effective on January 1, 2025.
\e\ The GWP for this compound was added to table A-1 in the final rule
  published on April 25, 2024 and effective on January 1, 2025.
\f\ For electronics manufacturing (as defined in Sec.   98.90), the term
  ``fluorinated GHGs'' in the definition of each fluorinated GHG group
  in Sec.   98.6 shall include fluorinated heat transfer fluids (as
  defined in Sec.   98.6), whether or not they are also fluorinated
  GHGs.
\g\ The GWP for this fluorinated GHG group was updated in the final rule
  published on April 25, 2024 and effective on January 1, 2025.


0
10. Revise and republish table A-3 to subpart A to read as follows:

    Table A-3 to Subpart A of Part 98--Source Category List for Sec.
                               98.2(a)(1)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories \a\ Applicable in Reporting Year 2010 and Future
 Years:
    Electricity generation units that report CO2 mass emissions year
     round through 40 CFR part 75 (subpart D).
    Adipic acid production (subpart E of this part).
    Aluminum production (subpart F of this part).
    Ammonia manufacturing (subpart G of this part).
    Cement production (subpart H of this part).
    HCFC-22 production (subpart O of this part).
    HFC-23 destruction processes that are not collocated with a HCFC-22
     production facility and that destroy more than 2.14 metric tons of
     HFC-23 per year (subpart O of this part).
    Lime manufacturing (subpart S of this part).
    Nitric acid production (subpart V of this part).
    Petrochemical production (subpart X of this part).
    Petroleum refineries (subpart Y of this part).
    Phosphoric acid production (subpart Z of this part).
    Silicon carbide production (subpart BB of this part).
    Soda ash production (subpart CC of this part).
    Titanium dioxide production (subpart EE of this part).
    Municipal solid waste landfills that generate CH4 in amounts
     equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart HH of this part.
    Manure management systems with combined CH4 and N2O emissions in
     amounts equivalent to 25,000 metric tons CO2e or more per year, as
     determined according to subpart JJ of this part.
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
 Future Years:
    Electrical transmission and distribution equipment use at facilities
     where the total estimated emissions from fluorinated GHGs, as
     determined under Sec.   98.301 (subpart DD of this part), are
     equivalent to 25,000 metric tons CO2e or more per year.
    Underground coal mines liberating 36,500,000 actual cubic feet of
     CH4 or more per year (subpart FF of this part).
    Geologic sequestration of carbon dioxide (subpart RR of this part).
    Injection of carbon dioxide (subpart UU of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2025 and
 Future Years:
    Geologic sequestration of carbon dioxide with enhanced oil recovery
     using ISO 27916 (subpart VV of this part).
    Coke calciners (subpart WW of this part).
    Calcium carbide production (subpart XX of this part).
    Caprolactam, glyoxal, and glyoxylic acid production (subpart YY of
     this part).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart of this
  part.


0
11. Revise and republish table A-4 to subpart A to read as follows:

    Table A-4 to Subpart A of Part 98--Source Category List for Sec.
                               98.2(a)(2)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
Source Categories \a\ Applicable in Reporting Year 2010 and Future
 Years:
    Ferroalloy production (subpart K of this part).
    Glass production (subpart N of this part).
    Hydrogen production (subpart P of this part).
    Iron and steel production (subpart Q of this part).
    Lead production (subpart R of this part).
    Pulp and paper manufacturing (subpart AA of this part).
    Zinc production (subpart GG of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
 Future Years:

[[Page 31900]]

 
    Electronics manufacturing (subpart I of this part).
    Fluorinated gas production (subpart L of this part).
    Magnesium production (subpart T of this part).
    Petroleum and Natural Gas Systems (subpart W of this part).
    Industrial wastewater treatment (subpart II of this part).
    Electrical transmission and distribution equipment manufacture or
     refurbishment, as determined under Sec.   98.451 (subpart SS of
     this part).
    Industrial waste landfills (subpart TT of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2025 and
 Future Years:
    Ceramics manufacturing facilities, as determined under Sec.   98.520
     (subpart ZZ of this part).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

Subpart C--General Stationary Fuel Combustion Sources

0
12. Amend Sec.  98.33 by:
0
a. Revising and republishing paragraph (a)(3)(iii);
0
b. Revising paragraph (b)(1)(vii);
0
c. Revising parameter ``EF'' of equation C-10 in paragraph (c)(4) 
introductory text;
0
d. Revising and republishing paragraph (c)(6);
0
e. Revising parameter ``R'' of equation C-11 in paragraph (d)(1); and
0
f. Revising the introductory text of paragraphs (e), (e)(1) and (3), 
and paragraph (e)(3)(iv).
    The revisions read as follows:


Sec.  98.33  Calculating GHG emissions.

* * * * *
    (a) * * *
    (3) * * *
    (iii) For a gaseous fuel, use equation C-5 to this section.
    [GRAPHIC] [TIFF OMITTED] TR25AP24.000
    

Where:

CO2 = Annual CO2 mass emissions from 
combustion of the specific gaseous fuel (metric tons).
Fuel = Annual volume of the gaseous fuel combusted (scf). The volume 
of fuel combusted must be measured directly, using fuel flow meters 
calibrated according to Sec.  98.3(i). Fuel billing meters may be 
used for this purpose.
CC = Annual average carbon content of the gaseous fuel (kg C per kg 
of fuel). The annual average carbon content shall be determined 
using the procedures specified in paragraphs (a)(3)(iii)(A)(1) and 
(2) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg per kg-
mole). The annual average molecular weight shall be determined using 
the procedures specified in paragraphs (a)(3)(iii)(B)(1) and (2) of 
this section.
MVC = Molar volume conversion factor at standard conditions, as 
defined in Sec.  98.6. Use 849.5 scf per kg mole if you select 68 
[deg]F as standard temperature and 836.6 scf per kg mole if you 
select 60 [deg]F as standard temperature.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (A) The minimum required sampling frequency for determining the 
annual average carbon content (e.g., monthly, quarterly, semi-annually, 
or by lot) is specified in Sec.  98.34. The method for computing the 
annual average carbon content for equation C-5 to this section is a 
function of unit size and how frequently you perform or receive from 
the fuel supplier the results of fuel sampling for carbon content. The 
methods are specified in paragraphs (a)(3)(iii)(A)(1) and (2) of this 
section, as applicable.
    (1) If the results of fuel sampling are received monthly or more 
frequently, then for each unit with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr (or for a group of units that 
includes at least one unit of that size), the annual average carbon 
content for equation C-5 shall be calculated using equation C-5A to 
this section. If multiple carbon content determinations are made in any 
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TR25AP24.001


Where:

(CC)annual = Weighted annual average carbon content of 
the fuel (kg C per kg of fuel).
(CC)i = Measured carbon content of the fuel, for sample 
period ``i'' (which may be the arithmetic average of multiple 
determinations), or, if applicable, an appropriate substitute data 
value (kg C per kg of fuel).
(Fuel)i = Volume of the fuel (scf) combusted during the 
sample period ``i'' (e.g., monthly, quarterly, semi-annually, or by 
lot) from company records.
(MW)i = Measured molecular weight of the fuel, for sample 
period ``i'' (which may be the arithmetic average of multiple 
determinations), or, if applicable, an appropriate substitute data 
value (kg per kg-mole).
MVC = Molar volume conversion factor at standard conditions, as 
defined in Sec.  98.6. Use 849.5 scf per kg-mole if you select 68 
[deg]F as standard temperature and 836.6

[[Page 31901]]

scf per kg-mole if you select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.

    (2) If the results of fuel sampling are received less frequently 
than monthly, or, for a unit with a maximum rated heat input capacity 
less than 100 mmBtu/hr (or a group of such units) regardless of the 
carbon content sampling frequency, the annual average carbon content 
for equation C-5 shall either be computed according to paragraph 
(a)(3)(iii)(A)(1) of this section or as the arithmetic average carbon 
content for all values for the year (including valid samples and 
substitute data values under Sec.  98.35).
    (B) The minimum required sampling frequency for determining the 
annual average molecular weight (e.g., monthly, quarterly, semi-
annually, or by lot) is specified in Sec.  98.34. The method for 
computing the annual average molecular weight for equation C-5 is a 
function of unit size and how frequently you perform or receive from 
the fuel supplier the results of fuel sampling for molecular weight. 
The methods are specified in paragraphs (a)(3)(iii)(B)(1) and (2) of 
this section, as applicable.
    (1) If the results of fuel sampling are received monthly or more 
frequently, then for each unit with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr (or for a group of units that 
includes at least one unit of that size), the annual average molecular 
weight for equation C-5 shall be calculated using equation C-5B to this 
section. If multiple molecular weight determinations are made in any 
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TR25AP24.002


Where:

(MW)annual = Weighted annual average molecular weight of 
the fuel (kg per kg-mole).
(MW)i = Measured molecular weight of the fuel, for sample 
period ``i'' (which may be the arithmetic average of multiple 
determinations), or, if applicable, an appropriate substitute data 
value (kg per kg-mole).
(Fuel)i = Volume of the fuel (scf) combusted during the 
sample period ``i'' (e.g., monthly, quarterly, semi-annually, or by 
lot) from company records.
MVC = Molar volume conversion factor at standard conditions, as 
defined in Sec.  98.6. Use 849.5 scf per kg-mole if you select 68 
[deg]F as standard temperature and 836.6 scf per kg-mole if you 
select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.

    (2) If the results of fuel sampling are received less frequently 
than monthly, or, for a unit with a maximum rated heat input capacity 
less than 100 mmBtu/hr (or a group of such units) regardless of the 
molecular weight sampling frequency, the annual average molecular 
weight for equation C-5 shall either be computed according to paragraph 
(a)(3)(iii)(B)(1) of this section or as the arithmetic average 
molecular weight for all values for the year (including valid samples 
and substitute data values under Sec.  98.35).
* * * * *
    (b) * * *
    (1) * * *
    (vii) May be used for the combustion of MSW and/or tires in a unit, 
provided that no more than 10 percent of the unit's annual heat input 
is derived from those fuels, combined.
* * * * *
    (c) * * *
    (4) * * *

EF = Fuel-specific emission factor for CH4 or 
N2O, from table C-2 to this subpart (kg CH4 or 
N2O per mmBtu).
* * * * *
    (6) Calculate the annual CH4 and N2O mass 
emissions from the combustion of blended fuels as follows:
    (i) If the mass, volume, or heat input of each component fuel in 
the blend is determined before the fuels are mixed and combusted, 
calculate and report CH4 and N2O emissions 
separately for each component fuel, using the applicable procedures in 
this paragraph (c).
    (ii) If the mass, volume, or heat input of each component fuel in 
the blend is not determined before the fuels are mixed and combusted, a 
reasonable estimate of the percentage composition of the blend, based 
on best available information, is required. Perform the following 
calculations for each component fuel ``i'' that is listed in table C-2 
to this subpart:
    (A) Multiply (% Fuel)i, the estimated mass, volume, or heat input 
percentage of component fuel ``i'' (expressed as a decimal fraction), 
by the total annual mass, volume, or heat input of the blended fuel 
combusted during the reporting year, to obtain an estimate of the 
annual value for component ``i'';
    (B) [Reserved]
    (C) Calculate the annual CH4 and N2O 
emissions from component ``i'', using equation C-8 (fuel mass or 
volume) to this section, C-8a (fuel heat input) to this section, C-8b 
(fuel heat input) to this section, C-9a (fuel mass or volume) to this 
section, or C-10 (fuel heat input) to this section, as applicable;
    (D) Sum the annual CH4 emissions across all component 
fuels to obtain the annual CH4 emissions for the blend. 
Similarly sum the annual N2O emissions across all component 
fuels to obtain the annual N2O emissions for the blend. 
Report these annual emissions totals.
    (d) * * *
    (1) * * *

R = The number of moles of CO2 released per mole of 
sorbent used (R = 1.00 when the sorbent is CaCO3 and the 
targeted acid gas species is SO2).
* * * * *
    (e) Biogenic CO2 emissions from combustion of biomass with other 
fuels. Use the applicable procedures of this paragraph (e) to estimate 
biogenic CO2 emissions from units that combust a combination 
of biomass and fossil fuels (i.e., either co-fired or blended fuels). 
Separate reporting of biogenic CO2 emissions from the 
combined combustion of biomass and fossil fuels is required for those 
biomass fuels listed in table C-1 to this subpart, MSW, and tires. In 
addition, when a biomass fuel that is not listed in table C-1 to this 
subpart is combusted in a unit that has a maximum rated heat input 
greater than 250 mmBtu/hr, if the biomass fuel accounts for 10% or more 
of the annual heat input to the unit, and if the unit does not use CEMS 
to quantify its annual CO2 mass emissions, then, pursuant to 
paragraph (b)(3)(iii) of this section, Tier 3 must be used to determine 
the carbon content of the biomass fuel and to calculate the biogenic 
CO2 emissions from combustion of the fuel. Notwithstanding 
these requirements, in accordance with Sec.  98.3(c)(12), separate 
reporting of biogenic CO2 emissions is optional for the 2010 
reporting year for units subject to subpart D of this part and for 
units

[[Page 31902]]

that use the CO2 mass emissions calculation methodologies in 
part 75 of this chapter, pursuant to paragraph (a)(5) of this section. 
However, if the owner or operator opts to report biogenic 
CO2 emissions separately for these units, the appropriate 
method(s) in this paragraph (e) shall be used.
    (1) You may use equation C-1 to this section to calculate the 
annual CO2 mass emissions from the combustion of the biomass 
fuels listed in table C-1 to this subpart, in a unit of any size, 
including units equipped with a CO2 CEMS, except when the 
use of Tier 2 is required as specified in paragraph (b)(1)(iv) of this 
section. Determine the quantity of biomass combusted using one of the 
following procedures in this paragraph (e)(1), as appropriate, and 
document the selected procedures in the Monitoring Plan under Sec.  
98.3(g):
* * * * *
    (3) You must use the procedures in paragraphs (e)(3)(i) through 
(iii) of this section to determine the annual biogenic CO2 
emissions from the combustion of MSW, except as otherwise provided in 
paragraph (e)(3)(iv) of this section. These procedures also may be used 
for any unit that co-fires biomass and fossil fuels, including units 
equipped with a CO2 CEMS.
* * * * *
    (iv) In lieu of following the procedures in paragraphs (e)(3)(i) 
through (iii) of this section, the procedures of this paragraph 
(e)(3)(iv) may be used for the combustion of tires regardless of the 
percent of the annual heat input provided by tires. The calculation 
procedure in this paragraph (e)(3)(iv) may be used for the combustion 
of MSW if the combustion of MSW provides no more than 10 percent of the 
annual heat input to the unit or if a small, batch incinerator combusts 
no more than 1,000 tons per year of MSW.
    (A) Calculate the total annual CO2 emissions from 
combustion of MSW and/or tires in the unit, using the applicable 
methodology in paragraphs (a)(1) through (3) of this section for units 
using Tier 1, Tier 2, or Tier 3; otherwise use the Tier 1 calculation 
methodology in paragraph (a)(1) of this section for units using either 
the Tier 4 or Alternative Part 75 calculation methodologies to 
calculate total CO2 emissions.
    (B) Multiply the result from paragraph (e)(3)(iv)(A) of this 
section by the appropriate default factor to determine the annual 
biogenic CO2 emissions, in metric tons. For MSW, use a 
default factor of 0.60 and for tires, use a default factor of 0.24.
* * * * *

0
13. Amend Sec.  98.34 by revising paragraphs (c)(6), (d) and (e) to 
read as follows:


Sec.  98.34  Monitoring and QA/QC requirements.

* * * * *
    (c) * * *
    (6) For applications where CO2 concentrations in process 
and/or combustion flue gasses are lower or higher than the typical 
CO2 span value for coal-based fuels (e.g., 20 percent 
CO2 for a coal fired boiler), cylinder gas audits of the 
CO2 monitor under appendix F to part 60 of this chapter may 
be performed at 40-60 percent and 80-100 percent of CO2 
span, in lieu of the prescribed calibration levels of 5-8 percent and 
10-14 percent CO2 by volume.
* * * * *
    (d) Except as otherwise provided in Sec.  98.33(e)(3)(iv), when 
municipal solid waste (MSW) is either the primary fuel combusted in a 
unit or the only fuel with a biogenic component combusted in the unit, 
determine the biogenic portion of the CO2 emissions using 
ASTM D6866-16 and ASTM D7459-08 (both incorporated by reference, see 
Sec.  98.7). Perform the ASTM D7459-08 sampling and the ASTM D6866-16 
analysis at least once in every calendar quarter in which MSW is 
combusted in the unit. Collect each gas sample during normal unit 
operating conditions for at least 24 total (not necessarily 
consecutive) hours, or longer if the facility deems it necessary to 
obtain a representative sample. Notwithstanding this requirement, if 
the types of fuels combusted and their relative proportions are 
consistent throughout the year, the minimum required sampling time may 
be reduced to 8 hours if at least two 8-hour samples and one 24-hour 
sample are collected under normal operating conditions, and arithmetic 
average of the biogenic fraction of the flue gas from the 8-hour 
samples (expressed as a decimal) is within 5 percent of the 
biogenic fraction from the 24-hour test. There must be no overlapping 
of the 8-hour and 24-hour test periods. Document the results of the 
demonstration in the unit's monitoring plan. If the types of fuels and 
their relative proportions are not consistent throughout the year, an 
optional sampling approach that facilities may wish to consider to 
obtain a more representative sample is to collect an integrated sample 
by extracting a small amount of flue gas (e.g., 1 to 5 cc) in each unit 
operating hour during the quarter. Separate the total annual 
CO2 emissions into the biogenic and non-biogenic fractions 
using the average proportion of biogenic emissions of all samples 
analyzed during the reporting year. Express the results as a decimal 
fraction (e.g., 0.30, if 30 percent of the CO2 is biogenic). 
When MSW is the primary fuel for multiple units at the facility, and 
the units are fed from a common fuel source, testing at only one of the 
units is sufficient.
    (e) For other units that combust combinations of biomass fuel(s) 
(or heterogeneous fuels that have a biomass component, e.g., tires) and 
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
16 and ASTM D7459-08 (both incorporated by reference, see Sec.  98.7) 
may be used to determine the biogenic portion of the CO2 
emissions in every calendar quarter in which biomass and non-biogenic 
fuels are co-fired in the unit. Follow the procedures in paragraph (d) 
of this section. If multiple units at the facility are fed from a 
common fuel source, testing at only one of the units is sufficient.
* * * * *

0
14. Amend Sec.  98.36 by revising paragraphs (c)(1)(vi), (c)(3)(vi), 
(e)(2)(ii)(C) and (e)(2)(xi) to read as follows:


Sec.  98.36  Data reporting requirements.

* * * * *
    (c) * * *
    (1) * * *
    (vi) Annual CO2 mass emissions and annual 
CH4, and N2O mass emissions, aggregated for each 
type of fuel combusted in the group of units during the report year, 
expressed in metric tons of each gas and in metric tons of 
CO2e. If any of the units burn biomass, report also the 
annual CO2 emissions from combustion of all biomass fuels 
combined, expressed in metric tons.
* * * * *
    (3) * * *
    (vi) If any of the units burns biomass, the annual CO2 
emissions from combustion of all biomass fuels from the units served by 
the common pipe, expressed in metric tons.
* * * * *
    (e) * * *
    (2) * * *
    (ii) * * *
    (C) The annual average, and, where applicable, monthly high heat 
values used in the CO2 emissions calculations for each type 
of fuel combusted during the reporting year, in mmBtu per short ton for 
solid fuels, mmBtu per gallon for

[[Page 31903]]

liquid fuels, and mmBtu per scf for gaseous fuels. Report an HHV value 
for each calendar month in which HHV determination is required. If 
multiple values are obtained in a given month, report the arithmetic 
average value for the month.
* * * * *
    (xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by 
reference, see Sec.  98.7) are used in accordance with Sec.  98.34(e) 
to determine the biogenic portion of the annual CO2 
emissions from a unit that co-fires biogenic fuels (or partly-biogenic 
fuels, including tires) and non-biogenic fuels, you shall report the 
results of each quarterly sample analysis, expressed as a decimal 
fraction (e.g., if the biogenic fraction of the CO2 
emissions is 30 percent, report 0.30).
* * * * *

0
15. Amend Sec.  98.37 by revising and republishing paragraph (b) to 
read as follows:


Sec.  98.37  Records that must be retained.

* * * * *
    (b) The applicable verification software records as identified in 
this paragraph (b). For each stationary fuel combustion source that 
elects to use the verification software specified in Sec.  98.5(b) 
rather than report data specified in paragraphs (b)(9)(iii), 
(c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (C), and (D), (e)(2)(iv)(A), (C), 
and (F), and (e)(2)(ix)(D) through (F) of this section, you must keep a 
record of the file generated by the verification software for the 
applicable data specified in paragraphs (b)(1) through (37) of this 
section. Retention of this file satisfies the recordkeeping requirement 
for the data in paragraphs (b)(1) through (37) of this section.
    (1) Mass of each solid fuel combusted (tons/year) (equation C-1 to 
Sec.  98.33).
    (2) Volume of each liquid fuel combusted (gallons/year) (equation 
C-1 to Sec.  98.33).
    (3) Volume of each gaseous fuel combusted (scf/year) (equation C-1 
to Sec.  98.33).
    (4) Annual natural gas usage (therms/year) (equation C-1a to Sec.  
98.33).
    (5) Annual natural gas usage (mmBtu/year) (equation C-1b to Sec.  
98.33).
    (6) Mass of each solid fuel combusted (tons/year) (equation C-2a to 
Sec.  98.33).
    (7) Volume of each liquid fuel combusted (gallons/year) (equation 
C-2a to Sec.  98.33).
    (8) Volume of each gaseous fuel combusted (scf/year) (equation C-2a 
to Sec.  98.33).
    (9) Measured high heat value of each solid fuel, for month (which 
may be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (mmBtu per ton) 
(equation C-2b to Sec.  98.33). Annual average HHV of each solid fuel 
(mmBtu per ton) (equation C-2a to Sec.  98.33).
    (10) Measured high heat value of each liquid fuel, for month (which 
may be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (mmBtu per gallons) 
(equation C-2b to Sec.  98.33). Annual average HHV of each liquid fuel 
(mmBtu per gallons) (equation C-2a to Sec.  98.33).
    (11) Measured high heat value of each gaseous fuel, for month 
(which may be the arithmetic average of multiple determinations), or, 
if applicable, an appropriate substitute data value (mmBtu per scf) 
(equation C-2b to Sec.  98.33). Annual average HHV of each gaseous fuel 
(mmBtu per scf) (equation C-2a to Sec.  98.33).
    (12) Mass of each solid fuel combusted during month (tons) 
(equation C-2b to Sec.  98.33).
    (13) Volume of each liquid fuel combusted during month (gallons) 
(equation C-2b to Sec.  98.33).
    (14) Volume of each gaseous fuel combusted during month (scf) 
(equation C-2b, equation C-5A, equation C-5B to Sec.  98.33).
    (15) Total mass of steam generated by municipal solid waste or each 
solid fuel combustion during the reporting year (pounds steam) 
(equation C-2c to Sec.  98.33).
    (16) Ratio of the boiler's maximum rated heat input capacity to its 
design rated steam output capacity (MMBtu/pounds steam) (equation C-2c 
to Sec.  98.33).
    (17) Annual mass of each solid fuel combusted (short tons/year) 
(equation C-3 to Sec.  98.33).
    (18) Annual average carbon content of each solid fuel (percent by 
weight, expressed as a decimal fraction) (equation C-3 to Sec.  98.33). 
Where applicable, monthly carbon content of each solid fuel (which may 
be the arithmetic average of multiple determinations), or, if 
applicable, an appropriate substitute data value (percent by weight, 
expressed as a decimal fraction) (equation C-2b to Sec.  98.33--see the 
definition of ``CC'' in equation C-3 to Sec.  98.33).
    (19) Annual volume of each liquid fuel combusted (gallons/year) 
(equation C-4 to Sec.  98.33).
    (20) Annual average carbon content of each liquid fuel (kg C per 
gallon of fuel) (equation C-4 to Sec.  98.33). Where applicable, 
monthly carbon content of each liquid fuel (which may be the arithmetic 
average of multiple determinations), or, if applicable, an appropriate 
substitute data value (kg C per gallon of fuel) (equation C-2b to Sec.  
98.33--see the definition of ``CC'' in equation C-3 to Sec.  98.33).
    (21) Annual volume of each gaseous fuel combusted (scf/year) 
(equation C-5 to Sec.  98.33).
    (22) Annual average carbon content of each gaseous fuel (kg C per 
kg of fuel) (equation C-5 to Sec.  98.33). Where applicable, monthly 
carbon content of each gaseous (which may be the arithmetic average of 
multiple determinations), or, if applicable, an appropriate substitute 
data value (kg C per kg of fuel) (equation C-5A to Sec.  98.33).
    (23) Annual average molecular weight of each gaseous fuel (kg/kg-
mole) (equation C-5 to Sec.  98.33). Where applicable, monthly 
molecular weight of each gaseous (which may be the arithmetic average 
of multiple determinations), or, if applicable, an appropriate 
substitute data value (kg/kg-mole) (equation C-5B to Sec.  98.33).
    (24) Molar volume conversion factor at standard conditions, as 
defined in Sec.  98.6 (scf per kg-mole) (equation C-5 to Sec.  98.33).
    (25) Identify for each fuel if you will use the default high heat 
value from table C-1 to this subpart, or actual high heat value data 
(equation C-8 to Sec.  98.33).
    (26) High heat value of each solid fuel (mmBtu/tons) (equation C-8 
to Sec.  98.33).
    (27) High heat value of each liquid fuel (mmBtu/gallon) (equation 
C-8 to Sec.  98.33).
    (28) High heat value of each gaseous fuel (mmBtu/scf) (equation C-8 
to Sec.  98.33).
    (29) Cumulative annual heat input from combustion of each fuel 
(mmBtu) (equation C-10 to Sec.  98.33).
    (30) Total quantity of each solid fossil fuel combusted in the 
reporting year, as defined in Sec.  98.6 (pounds) (equation C-13 to 
Sec.  98.33).
    (31) Total quantity of each liquid fossil fuel combusted in the 
reporting year, as defined in Sec.  98.6 (gallons) (equation C-13 to 
Sec.  98.33).
    (32) Total quantity of each gaseous fossil fuel combusted in the 
reporting year, as defined in Sec.  98.6 (scf) (equation C-13 to Sec.  
98.33).
    (33) High heat value of the each solid fossil fuel (Btu/lb) 
(equation C-13 to Sec.  98.33).
    (34) High heat value of the each liquid fossil fuel (Btu/gallons) 
(equation C-13 to Sec.  98.33).
    (35) High heat value of the each gaseous fossil fuel (Btu/scf) 
(equation C-13 to Sec.  98.33).

[[Page 31904]]

    (36) Fuel-specific carbon based F-factor per fuel (scf 
CO2/mmBtu) (equation C-13 to Sec.  98.33).
    (37) Moisture content used to calculate the wood and wood residuals 
wet basis HHV (percent), if applicable (equations C-1 and C-8 to Sec.  
98.33).

Subpart G--Ammonia Manufacturing

0
16. Amend Sec.  98.72 by revising paragraph (a) to read as follows:


Sec.  98.72  GHGs to report.

* * * * *
    (a) CO2 process emissions from steam reforming of a 
hydrocarbon or the gasification of solid and liquid raw material, 
reported for each ammonia manufacturing unit following the requirements 
of this subpart.
* * * * *

0
17. Amend Sec.  98.73 by revising the introductory text and paragraph 
(b) to read as follows:


Sec.  98.73  Calculating GHG emissions.

    You must calculate and report the annual CO2 process 
emissions from each ammonia manufacturing unit using the procedures in 
either paragraph (a) or (b) of this section.
* * * * *
    (b) Calculate and report under this subpart process CO2 
emissions using the procedures in paragraphs (b)(1) through (4) of this 
section, as applicable.
    (1) Gaseous feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from gaseous 
feedstock according to equation G-1 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.003

Where:

CO2,G = Annual CO2 emissions arising from 
gaseous feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock used in month n 
(scf of feedstock).
CCn = Carbon content of the gaseous feedstock, for month 
n (kg C per kg of feedstock), determined according to Sec.  
98.74(c).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (2) Liquid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from liquid 
feedstock according to equation G-2 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.004

Where:

CO2,L = Annual CO2 emissions arising from 
liquid feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used in month n 
(gallons of feedstock).
CCn = Carbon content of the liquid feedstock, for month n 
(kg C per gallon of feedstock) determined according to Sec.  
98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (3) Solid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from solid 
feedstock according to equation G-3 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.005

Where:

CO2,S = Annual CO2 emissions arising from 
solid feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in month n (kg 
of feedstock).
CCn = Carbon content of the solid feedstock, for month n 
(kg C per kg of feedstock), determined according to Sec.  98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (4) CO2 process emissions. You must calculate the annual 
CO2 process emissions at each ammonia manufacturing unit 
according to equation G-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.006

Where:

CO2 = Annual CO2 process emissions from each 
ammonia manufacturing unit (metric tons).
CO2,p = Annual CO2 process emissions arising 
from feedstock consumption based on feedstock type ``p'' (metric 
tons/yr) as calculated in paragraphs (b)(1) through (3) of this 
section.
p = Index for feedstock type; 1 indicates gaseous feedstock; 2 
indicates liquid feedstock; and 3 indicates solid feedstock.
* * * * *

0
18. Amend Sec.  98.76 by revising the introductory text and paragraphs 
(b)(1) and (13) and adding paragraph (b)(16) to read as follows:

[[Page 31905]]

Sec.  98.76   Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable for each ammonia manufacturing 
unit.
* * * * *
    (b) * * *
    (1) Annual CO2 process emissions (metric tons) for each 
ammonia manufacturing unit.
* * * * *
    (13) Annual amount of CO2 (metric tons) collected from 
ammonia production and consumed on site for urea production and the 
method used to determine the CO2 consumed in urea 
production.
* * * * *
    (16) Annual quantity of excess hydrogen produced that is not 
consumed through the production of ammonia (metric tons).

Subpart H--Cement Production

0
19. Amend Sec.  98.83 by:
0
a. Revising paragraph (d)(1);
0
b. Revising parameters ``CKDCaO'' and ``CKDMgO'' 
of equation H-4 in paragraph (d)(2)(ii)(A); and
0
c. Revising paragraph (d)(3).
    The revisions read as follows:


Sec.  98.83  Calculating GHG emissions.

* * * * *
    (d) * * *
    (1) Calculate CO2 process emissions from all kilns at 
the facility using equation H-1 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.007

Where:

CO2 CMF = Annual process emissions of CO2 from 
cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2 from 
clinker production from kiln m, metric tons.
CO2 rm,m = Total annual emissions of CO2 from 
raw materials from kiln m, metric tons.
k = Total number of kilns at a cement manufacturing facility.

    (2) * * *
    (ii) * * *
    (A) * * *

CKDncCaO = Quarterly non-calcined CaO content of CKD not 
recycled to the kiln, wt-fraction.
* * * * *
CKDncMgO = Quarterly non-calcined MgO content of CKD not 
recycled to the kiln, wt-fraction.
* * * * *
    (3) CO2 emissions from raw materials from each kiln. Calculate 
CO2 emissions from raw materials using equation H-5 to this 
section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.008

Where:

rm = The amount of raw material i consumed annually from kiln m, 
tons/yr (dry basis) or the amount of raw kiln feed consumed annually 
from kiln m, tons/yr (dry basis).
CO2,rm,m = Annual CO2 emissions from raw 
materials from kiln m.
TOCrm = Organic carbon content of raw material i from 
kiln m or organic carbon content of combined raw kiln feed (dry 
basis) from kiln m, as determined in Sec.  98.84(c) or using a 
default factor of 0.2 percent of total raw material weight.
M = Number of raw materials or 1 if calculating emissions based on 
combined raw kiln feed.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
* * * * *

0
20. Amend Sec.  98.86 by adding paragraphs (a)(4) through (8) and 
(b)(19) through (28) to read as follows:


Sec.  98.86   Data reporting requirements.

* * * * *
    (a) * * *
    (4) Annual arithmetic average of total CaO content of clinker at 
the facility, wt-fraction.
    (5) Annual arithmetic average of non-calcined CaO content of 
clinker at the facility, wt-fraction.
    (6) Annual arithmetic average of total MgO content of clinker at 
the facility, wt-fraction.
    (7) Annual arithmetic average of non-calcined MgO content of 
clinker at the facility, wt-fraction.
    (8) Annual facility CKD not recycled to the kiln(s), tons.
    (b) * * *
    (19) Annual arithmetic average of total CaO content of clinker at 
the facility, wt-fraction.
    (20) Annual arithmetic average of non-calcined CaO content of 
clinker at the facility, wt-fraction.
    (21) Annual arithmetic average of total MgO content of clinker at 
the facility, wt-fraction.
    (22) Annual arithmetic average of non-calcined MgO content of 
clinker at the facility, wt-fraction.
    (23) Annual arithmetic average of total CaO content of CKD not 
recycled to the kiln(s) at the facility, wt-fraction.
    (24) Annual arithmetic average of non-calcined CaO content of CKD 
not recycled to the kiln(s) at the facility, wt-fraction.
    (25) Annual arithmetic average of total MgO content of CKD not 
recycled to the kiln(s) at the facility, wt-fraction.
    (26) Annual arithmetic average of non-calcined MgO content of CKD 
not recycled to the kiln(s) at the facility, wt-fraction.
    (27) Annual facility CKD not recycled to the kiln(s), tons.
    (28) The amount of raw kiln feed consumed annually at the facility, 
tons (dry basis).

Subpart I--Electronics Manufacturing

0
21. Revise and republish Sec.  98.91 to read as follows:


Sec.  98.91   Reporting threshold.

    (a) You must report GHG emissions under this subpart if electronics 
manufacturing production processes, as defined in Sec.  98.90, are 
performed at your facility and your facility meets the requirements of 
either Sec.  98.2(a)(1) or (2). To calculate total annual GHG emissions 
for comparison to the 25,000 metric ton CO2e per year 
emission threshold in Sec.  98.2(a)(2), follow the requirements of 
Sec.  98.2(b), with one exception. Rather than using the calculation 
methodologies in Sec.  98.93 to calculate emissions from electronics 
manufacturing production processes, calculate emissions of each 
fluorinated GHG from electronics manufacturing production processes by 
using paragraph (a)(1), (2), or (3) of this section, as appropriate, 
and then sum

[[Page 31906]]

the emissions of each fluorinated GHG and account for fluorinated heat 
transfer fluid emissions by using paragraph (a)(4) of this section.
    (1) If you manufacture semiconductors or MEMS you must calculate 
annual production process emissions resulting from the use of each 
input gas for threshold applicability purposes using either the default 
emission factors shown in table I-1 to this subpart and equation I-1A 
to this section, or the consumption of each input gas, the default 
emission factors shown in table I-2 to this subpart, and equation I-1B 
to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.009

Where:

Ei = Annual production process emissions of gas i for 
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as 
calculated using equation I-5 to this section (m\2\).
EFi = Emission factor for gas i (kg/m\2\) shown in table 
I-1 to this subpart.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TR25AP24.010

Where:

Ei = Annual production process emissions resulting from 
the use of input gas i for threshold applicability purposes (metric 
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption 
(kg). Only gases that are used in semiconductor or MEMS 
manufacturing processes listed at Sec.  98.90(a)(1) through (4) must 
be considered for threshold applicability purposes.
(1-Ui), BCF4, and BC2F6 
= Default emission factors for the gas consumption-based threshold 
applicability determination listed in table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (2) If you manufacture LCDs, you must calculate annual production 
process emissions resulting from the use of each input gas for 
threshold applicability purposes using either the default emission 
factors shown in table I-1 to this subpart and equation I-2A to this 
section or the consumption of each input gas, the default emission 
factors shown in table I-2 to this subpart, and equation I-2B to this 
section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.011

Where:

Ei = Annual production process emissions of gas i for 
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as 
calculated using equation I-5 to this section (m\2\).
EFi = Emission factor for gas i (g/m\2\).
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
0.000001 = Conversion factor from g to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TR25AP24.012

Where:

Ei = Annual production process emissions resulting from 
the use of input gas i for threshold applicability purposes (metric 
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption 
(kg). Only gases that are used in LCD manufacturing processes listed 
at Sec.  98.90(a)(1) through (4) must be considered for threshold 
applicability purposes.
(1-Ui), BCF4, and BC2F6 
= Default emission factors for the gas consumption-based threshold 
applicability determination listed in table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (3) If you manufacture PVs, you must calculate annual production 
process emissions resulting from the use of each input gas i for 
threshold applicability purposes using gas-appropriate GWP values shown 
in table A-1 to subpart A of this part, the default emission factors 
shown in table I-2 to this subpart, and equation I-3 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.013

Where:

Ei = Annual production process emissions resulting from 
the use of input gas i for threshold applicability purposes (metric 
tons CO2e).
Ci = Annual fluorinated GHG (input gas i) purchases or 
consumption (kg). Only gases that are used in PV manufacturing 
processes listed at Sec.  98.90(a)(1) through (4) must be considered 
for threshold applicability purposes.
(1 - Ui), BCF4, and 
BC2F6 = Default emission factors for the gas 
consumption-based threshold applicability determination listed in 
table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (4) You must calculate total annual production process emissions 
for threshold applicability purposes using equation I-4 to this 
section.

[[Page 31907]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.014

Where:

ET = Annual production process emissions of all 
fluorinated GHGs for threshold applicability purposes (metric tons 
CO2e).
[delta] = Factor accounting for fluorinated heat transfer fluid 
emissions, estimated as 10 percent of total annual production 
process emissions at a semiconductor facility. Set equal to 1.1 when 
equation I-4 to this section is used to calculate total annual 
production process emissions from semiconductor manufacturing. Set 
equal to 1 when equation I-4 to this section is used to calculate 
total annual production process emissions from MEMS, LCD, or PV 
manufacturing.
Ei = Annual production process emissions of gas i for 
threshold applicability purposes (metric tons CO2e), as 
calculated in equations I-1a, I-1b, I-2a, I-2b, or I-3 to this 
section.
i = Emitted gas.

    (b) You must calculate annual manufacturing capacity of a facility 
using equation I-5 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.015

Where:

S = 100 percent of annual manufacturing capacity of a facility 
(m\2\).
Wx = Maximum substrate starts of fab f in month x (m\2\ 
per month).
x = Month.

0
22. Amend Sec.  98.92 by revising paragraph (a) introductory text to 
read as follows:


Sec.  98.92  GHGs to report.

    (a) You must report emissions of fluorinated GHGs (as defined in 
Sec.  98.6), N2O, and fluorinated heat transfer fluids (as 
defined in Sec.  98.6). The fluorinated GHGs and fluorinated heat 
transfer fluids that are emitted from electronics manufacturing 
production processes include, but are not limited to, those listed in 
table I-21 to this subpart. You must individually report, as 
appropriate:
* * * * *

0
23. Amend Sec.  98.93 by:
0
a. Revising paragraph (a);
0
b. Revising the introductory text of paragraph (e);
0
c. Revising parameters ``UTij'' and ``Tdijp'' of 
equation I-15 in paragraph (g); and
0
d. Revising paragraphs (h)(1) and (i).
    The revisions read as follows:


Sec.  98.93   Calculating GHG emissions.

    (a) You must calculate total annual emissions of each fluorinated 
GHG emitted by electronics manufacturing production processes from each 
fab (as defined in Sec.  98.98) at your facility, including each input 
gas and each by-product gas. You must use either default gas 
utilization rates and by-product formations rates according to the 
procedures in paragraph (a)(1), (2), (6), or (7) of this section, as 
appropriate, or the stack test method according to paragraph (i) of 
this section, to calculate emissions of each input gas and each by-
product gas.
    (1) If you manufacture semiconductors, you must adhere to the 
procedures in paragraphs (a)(1)(i) through (iii) of this section. You 
must calculate annual emissions of each input gas and of each by-
product gas using equations I-6, I-7, and I-9 to this section. If your 
fab uses less than 50 kg of a fluorinated GHG in one reporting year, 
you may calculate emissions as equal to your fab's annual consumption 
for that specific gas as calculated in equation I-11 to this section, 
plus any by-product emissions of that gas calculated under paragraph 
(a) of this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.016

Where:

ProcesstypeEi = Annual emissions of input gas i from the 
process type on a fab basis (metric tons).
Eij = Annual emissions of input gas i from process sub-
type or process type j as calculated in equation I-8A to this 
section (metric tons).
N = The total number of process sub-types j that depends on the 
electronics manufacturing fab and emission calculation methodology. 
If Eij is calculated for a process type j in equation I-
8A to this section, N = 1.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TR25AP24.017

Where:

ProcesstypeBEk = Annual emissions of by-product gas k 
from the processes type on a fab basis (metric tons).
BEkij = Annual emissions of by-product gas k formed from 
input gas i used for process sub-type or process type j as 
calculated in equation I-8B to this section (metric tons).
N = The total number of process sub-types j that depends on the 
electronics manufacturing fab and emission calculation methodology. 
If BEkij is calculated for a process type j in equation 
I-8B to this section, N = 1.
i = Input gas.
j = Process sub-type, or process type.
k = By-product gas.

    (i) You must calculate annual fab-level emissions of each 
fluorinated GHG used for the plasma etching/wafer cleaning process type 
using default utilization and by-product formation rates as shown in 
table I-3 or I-4 to this subpart, and by using equations I-8A and I-8B 
to this section.

[[Page 31908]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.018

Where:

Eij = Annual emissions of input gas i from process sub-
type or process type j, on a fab basis (metric tons).
Cij = Amount of input gas i consumed for process sub-type 
or process type j, as calculated in equation I-13 to this section, 
on a fab basis (kg).
Uij = Process utilization rate for input gas i for 
process sub-type or process type j (expressed as a decimal 
fraction).
aij = Fraction of input gas i used in process sub-type or 
process type j with abatement systems, on a fab basis (expressed as 
a decimal fraction).
dij = Fraction of input gas i destroyed or removed when 
fed into abatement systems by process tools where process sub-type, 
or process type j is used, on a fab basis, calculated by taking the 
tool weighted average of the claimed DREs for input gas i on tools 
that use process type or process sub-type j (expressed as a decimal 
fraction). This is zero unless the facility adheres to the 
requirements in Sec.  98.94(f).
UTij = The average uptime factor of all abatement systems 
connected to process tools in the fab using input gas i in process 
sub-type or process type j, as calculated in equation I-15 to this 
section, on a fab basis (expressed as a decimal fraction).
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TR25AP24.019

Where:

BEkij = Annual emissions of by-product gas k formed from 
input gas i from process sub-type or process type j, on a fab basis 
(metric tons).
Bkij = By-product formation rate of gas k created as a 
by-product per amount of input gas i (kg) consumed by process sub-
type or process type j (kg). If all input gases consumed by a 
chamber cleaning process sub-type are non-carbon containing input 
gases, this is zero when the combination of the non-carbon 
containing input gas and chamber cleaning process sub-type is never 
used to clean chamber walls on equipment that process carbon-
containing films during the year (e.g., when NF3 is used 
in remote plasma cleaning processes to only clean chambers that 
never process carbon-containing films during the year). If all input 
gases consumed by an etching and wafer cleaning process sub-type are 
non-carbon containing input gases, this is zero when the combination 
of the non-carbon containing input gas and etching and wafer 
cleaning process sub-type is never used to etch or wafer clean 
carbon-containing films during the year.
Cij = Amount of input gas i consumed for process sub-
type, or process type j, as calculated in equation I-13 to this 
section, on a fab basis (kg).
akij = Fraction of input gas i used for process sub-type, 
or process type j with abatement systems, on a fab basis (expressed 
as a decimal fraction).
dkij = Fraction of by-product gas k destroyed or removed 
in when fed into abatement systems by process tools where process 
sub-type or process type j is used, on a fab basis, calculated by 
taking the tool weighted average of the claimed DREs for by-product 
gas k on tools that use input gas i in process type or process sub-
type j (expressed as a decimal fraction). This is zero unless the 
facility adheres to the requirements in Sec.  98.94(f).
UTkij = The average uptime factor of all abatement 
systems connected to process tools in the fab emitting by-product 
gas k, formed from input gas i in process sub-type or process type 
j, on a fab basis (expressed as a decimal fraction). For this 
equation, UTkij is assumed to be equal to UTij 
as calculated in equation I-15 to this section.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
k = By-product gas.

    (ii) You must calculate annual fab-level emissions of each 
fluorinated GHG used for each of the process sub-types associated with 
the chamber cleaning process type, including in-situ plasma chamber 
clean, remote plasma chamber clean, and in-situ thermal chamber clean, 
using default utilization and by-product formation rates as shown in 
table I-3 or I-4 to this subpart, and by using equations I-8A and I-8B 
to this section.
    (iii) If default values are not available for a particular input 
gas and process type or sub-type combination in tables I-3 or I-4, you 
must follow the procedures in paragraph (a)(6) of this section.
    (2) If you manufacture MEMS or PVs and use semiconductor tools and 
processes, you may use Sec.  98.3(a)(1) to calculate annual fab-level 
emissions for those processes. For all other tools and processes used 
to manufacture MEMs, LCD and PV, you must calculate annual fab-level 
emissions of each fluorinated GHG used for the plasma etching and 
chamber cleaning process types using default utilization and by-product 
formation rates as shown in table I-5, I-6, or I-7 to this subpart, as 
appropriate, and by using equations I-8A and I-8B to this section. If 
default values are not available for a particular input gas and process 
type or sub-type combination in tables I-5, I-6, or I-7 to this 
subpart, you must follow the procedures in paragraph (a)(6) of this 
section. If your fab uses less than 50 kg of a fluorinated GHG in one 
reporting year, you may calculate emissions as equal to your fab's 
annual consumption for that specific gas as calculated in equation I-11 
to this section, plus any by-product emissions of that gas calculated 
under this paragraph (a).
    (3)-(5) [Reserved]
    (6) If you are required, or elect, to perform calculations using 
default emission factors for gas utilization and by-product formation 
rates according to the procedures in paragraph (a)(1) or (2) of this 
section, and default values are not available for a particular input 
gas and process type or sub-type combination in tables I-3, I-4, I-5, 
I-6, or I-7 to this subpart, you must use a utilization rate 
(Uij) of 0.2 (i.e., a 1-Uij of 0.8) and by-
product formation rates of 0.15 for CF4 and 0.05 for 
C2F6 and use equations I-8A and I-8B to this 
section.
    (7) If your fab employs hydrocarbon-fuel-based combustion emissions 
control systems (HC fuel CECS), including, but not limited to, 
abatement systems as defined at Sec.  98.98, that were purchased and 
installed on or after January 1, 2025, to control emissions from tools 
that use either NF3 in remote plasma cleaning processes or 
F2 as an input gas in any process type or sub-type, you must 
calculate the amount CF4 produced within and emitted from 
such systems using equation I-9 to this section using default 
utilization and by-product formation rates as shown in table I-3 or I-4 
to this subpart. A HC fuel CECS is assumed not to form CF4 
from F2 if the electronics manufacturer can certify that the 
rate of conversion from F2 to CF4 is <0.1% for 
that HC fuel CECS.

[[Page 31909]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.020

Where:

EABCF4 = Emissions of CF4 from HC fuel CECS 
when direct reaction between hydrocarbon fuel and F2 is 
not certified not to occur by the emissions control system 
manufacturer or electronics manufacturer, kg.
CF2,j = Amount of F2 consumed for process type 
or sub-type j, as calculated in equation I-13 to this section, on a 
fab basis (kg).
UF2,j = Process utilization rate for F2 for 
process type or sub-type j (expressed as a decimal fraction).
aF2,j = Within process sub-type or process type j, 
fraction of F2 used in process tools with HC fuel CECS 
that are not certified not to form CF4, on a fab basis, 
where the numerator is the number of tools that are equipped with HC 
fuel CECS that are not certified not to form CF4 that use 
F2 in process type j and the denominator is the total 
number of tools in the fab that use F2 in process type j 
(expressed as a decimal fraction).
UTF2,j = The average uptime factor of all HC fuel CECS 
connected to process tools in the fab using F2 in process 
sub-type or process type j (expressed as a decimal fraction).
ABCF4,F2 = Mass fraction of F2 in process 
exhaust gas that is converted into CF4 by direct reaction 
with hydrocarbon fuel in a HC fuel CECS. The default value of 
ABCF4,F2 = 0.116.
CNF3,RPC = Amount of NF3 consumed in remote 
plasma cleaning processes, as calculated in equation I-13 to this 
section, on a fab basis (kg).
BF2,NF3 = By-product formation rate of F2 
created as a by-product per amount of NF3 (kg) consumed 
in remote plasma cleaning processes (kg).
aNF3,RPC = Within remote plasma cleaning processes, 
fraction of NF3 used in process tools with HC fuel CECS 
that are not certified not to form CF4, where the 
numerator is the number of tools running remote plasma cleaning 
processes that are equipped with HC fuel CECS that are not certified 
not to form CF4 that use NF3 and the 
denominator is the total number of tools that run remote plasma 
clean processes in the fab that use NF3 (expressed as 
decimal fraction).
UTNF3,RPC,F2 = The average uptime factor of all HC fuel 
CECS connected to process tools in the fab emitting by-product gas 
F2, formed from input gas NF3 in remote plasma 
cleaning processes, on a fab basis (expressed as a decimal 
fraction). For this equation, UTNF3,RPC,F2 is assumed to 
be equal to UTNF3,RPC as calculated in equation I-15 to 
this section.
j = Process type or sub-type.
* * * * *
    (e) You must calculate the amount of input gas i consumed, on a fab 
basis, for each process sub-type or process type j, using equation I-13 
to this section. Where a gas supply system serves more than one fab, 
equation I-13 to this section is applied to that gas which has been 
apportioned to each fab served by that system using the apportioning 
factors determined in accordance with Sec.  98.94(c). If you elect to 
calculate emissions using the stack test method in paragraph (i) of 
this section and to use this paragraph (e) to calculate the fraction 
each fluorinated input gas i exhausted from tools with abatement 
systems and the fraction of each by-product gas k exhausted from tools 
with abatement systems, you may substitute ``The set of tools with 
abatement systems'' for ``Process sub-type or process type'' in the 
definition of ``j'' in equation I-13 to this section.
* * * * *
    (g) * * *

UTij = The average uptime factor of all abatement systems 
connected to process tools in the fab using input gas i in process 
sub-type or process type j (expressed as a decimal fraction). The 
average uptime factor may be set to one (1) if all the abatement 
systems for the relevant input gas i and process sub-type or type j 
are interlocked with all the tools using input gas i in process sub-
type or type j and feeding the abatement systems such that no gas 
can flow to the tools if the abatement systems are not in 
operational mode.
Tdijp = The total time, in minutes, that abatement system 
p, connected to process tool(s) in the fab using input gas i in 
process sub-type or process type j, is not in operational mode, as 
defined in Sec.  98.98, when at least one of the tools connected to 
abatement system p is in operation. If your fab uses redundant 
abatement systems, you may account for Tdijp as specified 
in Sec.  98.94(f)(4)(vi).
* * * * *
    (h) * * *
    (1) If you use a fluorinated chemical both as a fluorinated heat 
transfer fluid and in other applications, you may calculate and report 
either emissions from all applications or from only those specified in 
the definition of fluorinated heat transfer fluids in Sec.  98.6.
* * * * *
    (i) Stack test method. As an alternative to the default emission 
factor method in paragraph (a) of this section, you may calculate fab-
level fluorinated GHG emissions using fab-specific emission factors 
developed from stack testing. In this case, you must comply with the 
stack test method specified in paragraph (i)(3) of this section.
    (1)-(2) [Reserved]
    (3) Stack system stack test method. For each stack system in the 
fab, measure the emissions of each fluorinated GHG from the stack 
system by conducting an emission test. In addition, measure the fab-
specific consumption of each fluorinated GHG by the tools that are 
vented to the stack systems tested. Measure emissions and consumption 
of each fluorinated GHG as specified in Sec.  98.94(j). Develop fab-
specific emission factors and calculate fab-level fluorinated GHG 
emissions using the procedures specified in paragraphs (i)(3)(i) 
through (viii) of this section. All emissions test data and procedures 
used in developing emission factors must be documented and recorded 
according to Sec.  98.97.
    (i) You must measure the fab-specific fluorinated GHG consumption 
of the tools that are vented to the stack systems during the emission 
test as specified in Sec.  98.94(j)(3). Calculate the consumption for 
each fluorinated GHG for the test period.
    (ii) You must calculate the emissions of each fluorinated GHG 
consumed as an input gas using equation I-17 to this section and each 
fluorinated GHG formed as a by-product gas using equation I-18 to this 
section and the procedures specified in paragraphs (i)(3)(ii)(A) 
through (E) of this section. If a stack system is comprised of multiple 
stacks, you must sum the emissions from each stack in the stack system 
when using equation I-17 or equation I-18 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.021


[[Page 31910]]


Where:

Eis = Total fluorinated GHG input gas i, emitted from 
stack system s, during the sampling period (kg).
Xism = Average concentration of fluorinated GHG input gas 
i in stack system s, during the time interval m (ppbv).
MWi = Molecular weight of fluorinated GHG input gas i (g/
g-mole).
Qs = Flow rate of the stack system s, during the sampling 
period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68 [deg]F 
and 1 atm).
[Delta]tm = Length of time interval m (minutes). Each 
time interval in the FTIR sampling period must be less than or equal 
to 60 minutes (for example an 8 hour sampling period would consist 
of at least 8 time intervals).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
i = Fluorinated GHG input gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.
[GRAPHIC] [TIFF OMITTED] TR25AP24.022

Where:

Eks = Total fluorinated GHG by-product gas k, emitted 
from stack system s, during the sampling period (kg).
Xks = Average concentration of fluorinated GHG by-product 
gas k in stack system s, during the time interval m (ppbv).
MWk = Molecular weight of the fluorinated GHG by-product 
gas k (g/g-mole).
Qs = Flow rate of the stack system s, during the sampling 
period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68 [deg]F 
and 1 atm).
[Delta]tm = Length of time interval m (minutes). Each 
time interval in the FTIR sampling period must be less than or equal 
to 60 minutes (for example an 8 hour sampling period would consist 
of at least 8 time intervals).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
k = Fluorinated GHG by-product gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.

    (A) If a fluorinated GHG is consumed during the sampling period, 
but emissions are not detected, use one-half of the field detection 
limit you determined for that fluorinated GHG according to Sec.  
98.94(j)(2) for the value of ``Xism'' in equation I-17 to 
this section.
    (B) If a fluorinated GHG is consumed during the sampling period and 
detected intermittently during the sampling period, use the detected 
concentration for the value of ``Xism'' in equation I-17 to 
this section when available and use one-half of the field detection 
limit you determined for that fluorinated GHG according to Sec.  
98.94(j)(2) for the value of ``Xism'' when the fluorinated 
GHG is not detected.
    (C) If an expected or possible by-product, as listed in table I-17 
to this subpart, is detected intermittently during the sampling period, 
use the measured concentration for ``Xksm'' in equation I-18 
to this section when available and use one-half of the field detection 
limit you determined for that fluorinated GHG according to Sec.  
98.94(j)(2) for the value of ``Xksm'' when the fluorinated 
GHG is not detected.
    (D) If a fluorinated GHG is not consumed during the sampling period 
and is an expected by-product gas as listed in table I-17 to this 
subpart and is not detected during the sampling period, use one-half of 
the field detection limit you determined for that fluorinated GHG 
according to Sec.  98.94(j)(2) for the value of ``Xksm'' in 
equation I-18 to this section.
    (E) If a fluorinated GHG is not consumed during the sampling period 
and is a possible by-product gas as listed in table I-17 to this 
subpart, and is not detected during the sampling period, then assume 
zero emissions for that fluorinated GHG for the tested stack system.
    (iii) You must calculate a fab-specific emission factor for each 
fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted 
per kg of input gas i consumed) in the tools that vent to stack 
systems, as applicable, using equations I-19A and I-19B to this section 
or equations I-19A and I-19C to this section. Use equation I-19A to 
this section to calculate the controlled emissions for each carbon-
containing fluorinated GHG that would result during the sampling period 
if the utilization rate for the input gas were equal to 0.2 
(Eimax,f). If SsEi,s (the total 
measured emissions of the fluorinated GHG across all stack systems, 
calculated based on the results of equation I-17 to this section) is 
less than or equal to Eimax,f calculated in equation I-19A 
to this section, use equation I-19B to this section to calculate the 
emission factor for that fluorinated GHG. If 
SsEi,s is larger than the Eimax,f 
calculated in equation I-19A to this section, use equation I-19C to 
this section to calculate the emission factor and treat the difference 
between the total measured emissions SsEi,s and 
the maximum expected controlled emissions Eimax,f as a by-
product of the other input gases, using equation I-20 to this section. 
For all fluorinated GHGs that do not contain carbon, use equation I-19B 
to this section to calculate the emission factor for that fluorinated 
GHG.
[GRAPHIC] [TIFF OMITTED] TR25AP24.023

Where:

Eimax,f = Maximum expected controlled emissions of gas i 
from its use an input gas during the stack testing period, from fab 
f (max kg emitted).
Activityif = Consumption of fluorinated GHG input gas i, 
for fab f, in the tools vented to the stack systems being tested, 
during the sampling period, as determined following the procedures 
specified in Sec.  98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab 
f, during the sampling period, as calculated in equation I-23 to 
this section (expressed as decimal fraction). If the stack system 
does not have abatement systems on the tools vented to the stack 
system, the value of this parameter is zero.
aif = Fraction of input gas i emitted from tools with 
abatement systems in fab f (expressed as a decimal fraction), as 
calculated in equation I-24C to this section.
dif = Fraction of fluorinated GHG input gas i destroyed 
or removed when fed into abatement systems by process tools in fab 
f, as calculated in equation I-24A to this section (expressed as 
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.

[[Page 31911]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.024

Where:

EFif = Emission factor for fluorinated GHG input gas i, 
from fab f, representing 100 percent abatement system uptime (kg 
emitted/kg input gas consumed).
Eis = Mass emission of fluorinated GHG input gas i from 
stack system s during the sampling period (kg emitted).
Activityif = Consumption of fluorinated GHG input gas i, 
for fab f during the sampling period, as determined following the 
procedures specified in Sec.  98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab 
f, during the sampling period, as calculated in equation I-23 to 
this section (expressed as decimal fraction). If the stack system 
does not have abatement systems on the tools vented to the stack 
system, the value of this parameter is zero.
aif = Fraction of fluorinated GHG input gas i exhausted 
from tools with abatement systems in fab f (expressed as a decimal 
fraction), as calculated in equation I-24C to this section.
dif = Fraction of fluorinated GHG input gas i destroyed 
or removed when fed into abatement systems by process tools in fab 
f, as calculated in equation I-24A to this section (expressed as 
decimal fraction). If the stack system does not have abatement 
systems on the tools vented to the stack system, the value of this 
parameter is zero.
f = Fab.
i = Fluorinated GHG input gas.
s = Stack system.
[GRAPHIC] [TIFF OMITTED] TR25AP24.025

EFif = Emission factor for input gas i, from fab f, 
representing a 20-percent utilization rate and a 100-percent 
abatement system uptime (kg emitted/kg input gas consumed).
aif = Fraction of input gas i emitted from tools with 
abatement systems in fab f (expressed as a decimal fraction), as 
calculated in equation I-24C to this section.
dif = Fraction of fluorinated GHG input gas i destroyed 
or removed when fed into abatement systems by process tools in fab 
f, as calculated in equation I-24A to this section (expressed as 
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.

    (iv) You must calculate a fab-specific emission factor for each 
fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg 
of total fluorinated GHG consumed) in the tools vented to stack 
systems, as applicable, using equation I-20 to this section. When 
calculating the by-product emission factor for an input gas for which 
SsEi,s equals or exceeds Eimax,f, 
exclude the consumption of that input gas from the term 
``S(Activityif).''
[GRAPHIC] [TIFF OMITTED] TR25AP24.026

Where:

EFkf = Emission factor for fluorinated GHG by-product gas 
k, from fab f, representing 100 percent abatement system uptime (kg 
emitted/kg of all input gases consumed in tools vented to stack 
systems).
Eks = Mass emission of fluorinated GHG by-product gas k, 
emitted from stack system s, during the sampling period (kg 
emitted).
Activityif = Consumption of fluorinated GHG input gas i 
for fab f in tools vented to stack systems during the sampling 
period as determined following the procedures specified in Sec.  
98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab 
f, during the sampling period, as calculated in equation I-23 to 
this section (expressed as decimal fraction).
akif = Fraction of by-product k emitted from tools using 
input gas i with abatement systems in fab f (expressed as a decimal 
fraction), as calculated using equation I-24D to this section.
dkif = Fraction of fluorinated GHG by-product gas k 
generated from input gas i destroyed or removed when fed into 
abatement systems by process tools in fab f, as calculated in 
equation I-24B to this section (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product gas.
s = Stack system.

    (v) You must calculate annual fab-level emissions of each 
fluorinated GHG consumed using equation I-21 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.027

Where:

Eif = Annual emissions of fluorinated GHG input gas i 
(kg/year) from the stack systems for fab f.
EFif = Emission factor for fluorinated GHG input gas i 
emitted from fab f, as calculated in equation I-19 to this section 
(kg emitted/kg input gas consumed).
Cif = Total consumption of fluorinated GHG input gas i in 
tools that are vented to stack systems, for fab f, for the reporting 
year, as calculated using equation I-13 to this section (kg/year).
UTf = The total uptime of all abatement systems for fab 
f, during the reporting year, as calculated using equation I-23 to 
this section (expressed as a decimal fraction).
aif = Fraction of fluorinated GHG input gas i emitted 
from tools with abatement systems in fab f (expressed as a decimal 
fraction), as calculated using equation I-24C or I-24D to this 
section.
dif = Fraction of fluorinated GHG input gas i destroyed 
or removed when fed into abatement systems by process tools in fab f 
that are included in the stack testing option, as calculated in 
equation I-24A to this section (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.

    (vi) You must calculate annual fab-level emissions of each 
fluorinated GHG

[[Page 31912]]

by-product formed using equation I-22 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.028

Where:

Ekf = Annual emissions of fluorinated GHG by-product gas 
k (kg/year) from the stack for fab f.
EFkf = Emission factor for fluorinated GHG by-product gas 
k, emitted from fab f, as calculated in equation I-20 to this 
section (kg emitted/kg of all fluorinated input gases consumed).
Cif = Total consumption of fluorinated GHG input gas i in 
tools that are vented to stack systems, for fab f, for the reporting 
year, as calculated using equation I-13 to this section.
UTf = The total uptime of all abatement systems for fab 
f, during the reporting year as calculated using equation I-23 to 
this section (expressed as a decimal fraction).
akif = Estimate of fraction of fluorinated GHG by-product 
gas k emitted in fab f from tools using input gas i with abatement 
systems (expressed as a decimal fraction), as calculated using 
equation I-24D to this section.
dkif = Fraction of fluorinated GHG by-product k generated 
from input gas i destroyed or removed when fed into abatement 
systems by process tools in fab f that are included in the stack 
testing option, as calculated in equation I-24B to this section 
(expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product.

    (vii) When using the stack testing method described in this 
paragraph (i), you must calculate abatement system uptime on a fab 
basis using equation I-23 to this section. When calculating abatement 
system uptime for use in equation I-19 and I-20 to this section, you 
must evaluate the variables ``Tdpf'' and ``UTpf'' for the sampling 
period instead of the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25AP24.029

Where:

UTf = The average uptime factor for all abatement systems 
in fab f (expressed as a decimal fraction). The average uptime 
factor may be set to one (1) if all the abatement systems in fab f 
are interlocked with all the tools feeding the abatement systems 
such that no gas can flow to the tools if the abatement systems are 
not in operational mode.
Tdpf = The total time, in minutes, that abatement system 
p, connected to process tool(s) in fab f, is not in operational mode 
as defined in Sec.  98.98. If your fab uses redundant abatement 
systems, you may account for Tdpf as specified in Sec.  
98.94(f)(4)(vi).
UTpf = Total time, in minutes per year, in which the 
tool(s) connected at any point during the year to abatement system 
p, in fab f could be in operation. For determining the amount of 
tool operating time, you may assume that tools that were installed 
for the whole of the year were operated for 525,600 minutes per 
year. For tools that were installed or uninstalled during the year, 
you must prorate the operating time to account for the days in which 
the tool was not installed; treat any partial day that a tool was 
installed as a full day (1,440 minutes) of tool operation. For an 
abatement system that has more than one connected tool, the tool 
operating time is 525,600 minutes per year if there was at least one 
tool installed at all times throughout the year. If you have tools 
that are idle with no gas flow through the tool, you may calculate 
total tool time using the actual time that gas is flowing through 
the tool.
f = Fab.
p = Abatement system.

    (viii) When using the stack testing option described in this 
paragraph (i) and when using more than one DRE for the same input gas i 
or by-product gas k, you must calculate the weighted-average fraction 
of each fluorinated input gas i and each fluorinated by-product gas k 
that has more than one DRE and that is destroyed or removed in 
abatement systems for each fab f, as applicable, by using equation I-
24A to this section (for input gases) and equation I-24B to this 
section (for by-product gases) and table I-18 to this subpart. If 
default values are not available in table I-18 for a particular input 
gas, you must use a value of 10.
[GRAPHIC] [TIFF OMITTED] TR25AP24.030

Where:

dif = The average weighted fraction of fluorinated GHG 
input gas i destroyed or removed when fed into abatement systems by 
process tools in fab f (expressed as a decimal fraction).
dkif = The average weighted fraction of fluorinated GHG 
by-product gas k generated from input gas i that is destroyed or 
removed when fed into abatement systems by process tools in fab f 
(expressed as a decimal fraction).
ni,p,DREy = Number of tools that use gas i, that run 
chamber cleaning process p, and that are equipped with abatement 
systems for gas i that have the DRE DREy.
mi,q,DREz = Number of tools that use gas i, that run etch 
and/or wafer cleaning processes, and that are equipped with 
abatement systems for gas i that have the DRE DREz.
ni,p,a = Total number of tools that use gas i, run 
chamber cleaning process type p, and that are equipped with 
abatement systems for gas i.
mi,q,a = Total number of tools that use gas i, run etch 
and/or wafer cleaning processes, and that are equipped with 
abatement systems for gas i.
nk,i,p,DREy = Number of tools that use gas i, generate 
by-product k, that run chamber cleaning process p, and that are 
equipped with abatement systems for gas i that have the DRE DREy.

[[Page 31913]]

mk,i,q,DREz = Number of tools that use gas i, generate 
by-product k, that run etch and/or wafer cleaning processes, and 
that are equipped with abatement systems for gas i that have the DRE 
DREz.
nk,i,p,a = Total number of tools that use gas i, generate 
by-product k, run chamber cleaning process type p, and that are 
equipped with abatement systems for gas i.
mk,i,q,a = Total number of tools that use gas i, generate 
by-product k, run etch and/or wafer cleaning processes, and that are 
equipped with abatement systems for gas i.
gi,p = Default factor reflecting the ratio of 
uncontrolled emissions per tool of input gas i from tools running 
process sub-type p processes to uncontrolled emissions per tool of 
input gas i from process tools running process type q processes.
gk,i,p = Default factor reflecting the ratio of 
uncontrolled emissions per tool of input gas i from tools running 
process sub-type p processes to uncontrolled emissions per tool of 
input gas i from process tools running process type q processes.
DREy = Default or alternative certified DRE for gas i for 
abatement systems connected to CVD tool.
DREz = Default or alternative certified DRE for gas i for 
abatement systems connected to etching and/or wafer cleaning tool.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that 
consists of the combination of etching and/or wafer cleaning 
processes.
f = Fab.
i = Fluorinated GHG input gas.

    (ix) When using the stack testing method described in this 
paragraph (i), you must calculate the fraction each fluorinated input 
gas i exhausted in fab f from tools with abatement systems and the 
fraction of each by-product gas k exhausted from tools with abatement 
systems, as applicable, by following either the procedure set forth in 
paragraph (i)(3)(ix)(A) of this section or the procedure set forth in 
paragraph (i)(3)(ix)(B) of this section.
    (A) Use equation I-24C to this section (for input gases) and 
equation I-24D to this section (for by-product gases) and table I-18 to 
this subpart. If default values are not available in table I-18 for a 
particular input gas, you must use a value of 10.
[GRAPHIC] [TIFF OMITTED] TR25AP24.031

Where:

aif = Fraction of fluorinated input gas i exhausted from 
tools with abatement systems in fab f (expressed as a decimal 
fraction).
ni,p,a = Number of tools that use gas i, that run chamber 
cleaning process sub-type p, and that are equipped with abatement 
systems for gas i.
mi,q,a = Number of tools that use gas i, that run etch 
and/or wafer cleaning processes, and that are equipped with 
abatement systems for gas i.
ni,p = Total number of tools using gas i and running 
chamber cleaning process sub-type p.
mi,q = Total number of tools using gas i and running etch 
and/or wafer cleaning processes.
gi,p = Default factor reflecting the ratio of 
uncontrolled emissions per tool of input gas i from tools running 
process type p processes to uncontrolled emissions per tool of input 
gas i from process tools running process type q processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that 
consists of the combination of etching and/or wafer cleaning 
processes.
[GRAPHIC] [TIFF OMITTED] TR25AP24.032

Where:

ak,i,f = Fraction of by-product gas k exhausted from 
tools using input gas i with abatement systems in fab f (expressed 
as a decimal fraction).
nk,i,p,a = Number of tools that exhaust by-product gas k 
from input gas i, that run chamber cleaning process p, and that are 
equipped with abatement systems for gas k.
mk,i,q,a = Number of tools that exhaust by-product gas k 
from input gas i, that run etch and/or wafer cleaning processes, and 
that are equipped with abatement systems for gas k.
nk,i,p = Total number of tools emitting by-product k from 
input gas i and running chamber cleaning process p.
mk,i,q = Total number of tools emitting by-product k from 
input gas i and running etch and/or wafer cleaning processes.
gk,i,p = Default factor reflecting the ratio of 
uncontrolled emissions per tool of by-product gas k from input gas i 
from tools running chamber cleaning process p to uncontrolled 
emissions per tool of by-product gas k from input gas i from process 
tools running etch and/or wafer cleaning processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that 
consists of the combination of etching and/or wafer cleaning 
processes.

    (B) Use paragraph (e) of this section to apportion consumption of 
gas i either to tools with abatement systems and tools without 
abatement systems or to each process type or sub-type, as applicable. 
If you apportion consumption of gas i to each process type or sub-type, 
calculate the fractions of input gas i and by-product gas k formed from 
gas i that are exhausted from tools with abatement systems based on the 
numbers of tools with and without abatement systems within each process 
type or sub-type.
    (4) Method to calculate emissions from fluorinated GHGs that are 
not tested. Calculate emissions from consumption of each intermittent 
low-use fluorinated GHG as defined in Sec.  98.98 of this subpart using 
the default utilization and by-product formation rates provided in 
table I-11, I-12, I-13, I-14, or I-15 to this subpart, as applicable, 
and by using equations I-8A, I-8B, I-9, and I-13 to this section. If a 
fluorinated GHG was not being used during the stack testing and does 
not meet the definition of intermittent low-use fluorinated GHG in 
Sec.  98.98, then you must test the stack systems associated with the 
use of that fluorinated GHG at a time when that gas is in use at a 
magnitude that would allow you to determine an emission factor for that 
gas according to the procedures specified in paragraph (i)(3) of this 
section.
    (5) [Reserved]

0
24. Amend Sec.  98.94 by:
0
a. Revising paragraph (c) introductory text;
0
b. Adding paragraph (e);
0
c. Revising paragraphs (f)(3), (f)(4) introductory text, (f)(4)(iii), 
(j)(1) introductory text, (j)(1)(i), (j)(3) introductory text, and 
(j)(5); and
0
d. Removing and reserving paragraphs (j)(6) and (j)(8)(v).
    The revisions and addition read as follows:

[[Page 31914]]

Sec.  98.94  Monitoring and QA/QC requirements.

* * * * *
    (c) You must develop apportioning factors for fluorinated GHG and 
N2O consumption (including the fraction of gas consumed by 
process tools connected to abatement systems as in equations I-8A, I-
8B, I-9, and I-10 to Sec.  98.93), to use in the equations of this 
subpart for each input gas i, process sub-type, process type, stack 
system, and fab as appropriate, using a fab-specific engineering model 
that is documented in your site GHG Monitoring Plan as required under 
Sec.  98.3(g)(5). This model must be based on a quantifiable metric, 
such as wafer passes or wafer starts, or direct measurement of input 
gas consumption as specified in paragraph (c)(3) of this section. To 
verify your model, you must demonstrate its precision and accuracy by 
adhering to the requirements in paragraphs (c)(1) and (2) of this 
section.
* * * * *
    (e) If you use HC fuel CECS purchased and installed on or after 
January 1, 2025 to control emissions from tools that use either 
NF3 as an input gas in remote plasma cleaning processes or 
F2 as an input gas in any process, and if you use a value 
less than 1 for either aF2,j or aNF3,RPC in 
equation I-9 to Sec.  98.93, you must certify and document that the 
model for each of the systems for which you are claiming that it does 
not form CF4 from F2 has been tested and verified 
to produce less than 0.1% CF4 from F2 and that 
each of the systems is installed, operated, and maintained in 
accordance with the directions of the HC fuel CECS manufacturer. 
Hydrocarbon-fuel-based combustion emissions control systems include but 
are not limited to abatement systems as defined in Sec.  98.98 that are 
hydrocarbon-fuel-based. The rate of conversion from F2 to 
CF4 must be measured using a scientifically sound, industry-
accepted method that accounts for dilution through the abatement 
device, such as EPA 430-R-10-003 (incorporated by reference, see Sec.  
98.7), adjusted to calculate the rate of conversion from F2 
to CF4 rather than the DRE. Either the HC fuel CECS 
manufacturer or the electronics manufacturer may perform the 
measurement. The flow rate of F2 into the tested HC fuel 
CECS may be metered using a calibrated mass flow controller.
    (f) * * *
    (3) If you use default destruction and removal efficiency values in 
your emissions calculations under Sec.  98.93(a), (b), and/or (i), you 
must certify and document that the abatement systems at your facility 
for which you use default destruction or removal efficiency values are 
specifically designed for fluorinated GHG or N2O abatement, 
as applicable, and provide the abatement system manufacturer-verified 
DRE value that meets (or exceeds) the default destruction or removal 
efficiency in table I-16 to this subpart for the fluorinated GHG or 
N2O. For abatement systems purchased and installed on or 
after January 1, 2025, you must also certify and document that the 
abatement system has been tested by the abatement system manufacturer 
based on the methods specified in paragraph (f)(3)(i) of this section 
and verified to meet (or exceed) the default destruction or removal 
efficiency in table I-16 for the fluorinated GHG or N2O 
under worst-case flow conditions as defined in paragraph (f)(3)(ii) of 
this section. If you use a verified destruction and removal efficiency 
value that is lower than the default in table I-16 to this subpart in 
your emissions calculations under Sec.  98.93(a), (b), and/or (i), you 
must certify and document that the abatement systems at your facility 
for which you use the verified destruction or removal efficiency values 
are specifically designed for fluorinated GHG or N2O 
abatement, as applicable, and provide the abatement system 
manufacturer-verified DRE value that is lower than the default 
destruction or removal efficiency in table I-16 for the fluorinated GHG 
or N2O. For abatement systems purchased and installed on or 
after January 1, 2025, you must also certify and document that the 
abatement system has been tested by the abatement system manufacturer 
based on the methods specified in paragraph (f)(3)(i) of this section 
and verified to meet or exceed the destruction or removal efficiency 
value used for that fluorinated GHG or N2O under worst-case 
flow conditions as defined in paragraph (f)(3)(ii) of this section. If 
you elect to calculate fluorinated GHG emissions using the stack test 
method under Sec.  98.93(i), you must also certify that you have 
included and accounted for all abatement systems designed for 
fluorinated GHG abatement and any respective downtime in your emissions 
calculations under Sec.  98.93(i)(3).
    (i) For purposes of paragraph (f)(3) of this section, destruction 
and removal efficiencies for abatement systems purchased and installed 
on or after January 1, 2025, must be measured using a scientifically 
sound, industry-accepted measurement methodology that accounts for 
dilution through the abatement system, such as EPA 430-R-10-003 
(incorporated by reference, see Sec.  98.7).
    (ii) Worst-case flow conditions are defined as the highest total 
fluorinated GHG or N2O flows through each model of emissions 
control systems (gas by gas and process type by process type across the 
facility) and the highest total flow scenarios (with N2 
dilution accounted for) across the facility during which the abatement 
system is claimed to be in operational mode.
    (4) If you calculate and report controlled emissions using neither 
the default destruction or removal efficiency values in table I-16 to 
this subpart nor an abatement system manufacturer-verified lower 
destruction or removal efficiency value per paragraph (f)(3) of this 
section, you must use an average of properly measured destruction or 
removal efficiencies for each gas and process sub-type or process type 
combination, as applicable, determined in accordance with procedures in 
paragraphs (f)(4)(i) through (vi) of this section. This includes 
situations in which your fab employs abatement systems not specifically 
designed for fluorinated GHG or N2O abatement or for which 
your fab operates abatement systems outside the range of parameters 
specified in the documentation supporting the certified DRE and you 
elect to reflect emission reductions due to these systems. You must not 
use a default value from table I-16 to this subpart for any abatement 
system not specifically designed for fluorinated GHG and N2O 
abatement, for any abatement system not certified to meet the default 
value from table I-16, or for any gas and process type combination for 
which you have measured the destruction or removal efficiency according 
to the requirements of paragraphs (f)(4)(i) through (vi) of this 
section.
* * * * *
    (iii) If you elect to take credit for abatement system destruction 
or removal efficiency before completing testing on 20 percent of the 
abatement systems for that gas and process sub-type or process type 
combination, as applicable, you must use default destruction or removal 
efficiencies or a verified destruction or removal efficiency, if 
verified at a lower value, for a gas and process type combination. You 
must not use a default value from table I-16 to this subpart for any 
abatement system not specifically designed for fluorinated GHG and 
N2O abatement, and must not take credit for abatement system 
destruction or removal efficiency before completing testing on 20 
percent of the abatement systems for that gas and process sub-

[[Page 31915]]

type or process type combination, as applicable. Following testing on 
20 percent of abatement systems for that gas and process sub-type or 
process type combination, you must calculate the average destruction or 
removal efficiency as the arithmetic mean of all test results for that 
gas and process sub-type or process type combination, until you have 
tested at least 30 percent of all abatement systems for each gas and 
process sub-type or process type combination. After testing at least 30 
percent of all systems for a gas and process sub-type or process type 
combination, you must use the arithmetic mean of the most recent 30 
percent of systems tested as the average destruction or removal 
efficiency. You may include results of testing conducted on or after 
January 1, 2011 for use in determining the site-specific destruction or 
removal efficiency for a given gas and process sub-type or process type 
combination if the testing was conducted in accordance with the 
requirements of paragraph (f)(4)(i) of this section.
* * * * *
    (j) * * *
    (1) Stack system testing. Conduct an emissions test for each stack 
system according to the procedures in paragraphs (j)(1)(i) through (iv) 
of this section.
    (i) You must conduct an emission test during which the fab is 
operating at a representative operating level, as defined in Sec.  
98.98, and with the abatement systems connected to the stack system 
being tested operating with at least 90-percent uptime, averaged over 
all abatement systems, during the 8-hour (or longer) period for each 
stack system, or at no less than 90 percent of the abatement system 
uptime rate measured over the previous reporting year, averaged over 
all abatement systems. Hydrocarbon-fuel-based combustion emissions 
control systems that were purchased and installed on or after January 
1, 2025, that are used to control emissions from tools that use either 
NF3 in remote plasma cleaning processes or F2 as 
an input gas in any process type or sub-type, and that are not 
certified not to form CF4, must operate with at least 90-
percent uptime during the test.
* * * * *
    (3) Fab-specific fluorinated GHG consumption measurements. You must 
determine the amount of each fluorinated GHG consumed by each fab 
during the sampling period for all process tools connected to the stack 
systems under Sec.  98.93(i)(3), according to the procedures in 
paragraphs (j)(3)(i) and (ii) of this section.
* * * * *
    (5) Emissions testing frequency. You must conduct emissions testing 
to develop fab-specific emission factors on a frequency according to 
the procedures in paragraph (j)(5)(i) or (ii) of this section.
    (i) Annual testing. You must conduct an annual emissions test for 
each stack system unless you meet the criteria in paragraph (j)(5)(ii) 
of this section to skip annual testing. Each set of emissions testing 
for a stack system must be separated by a period of at least 2 months.
    (ii) Criteria to test less frequently. After the first 3 years of 
annual testing, you may calculate the relative standard deviation of 
the emission factors for each fluorinated GHG included in the test and 
use that analysis to determine the frequency of any future testing. As 
an alternative, you may conduct all three tests in less than 3 calendar 
years for purposes of this paragraph (j)(5)(ii), but this does not 
relieve you of the obligation to conduct subsequent annual testing if 
you do not meet the criteria to test less frequently. If the criteria 
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met, 
you may use the arithmetic average of the three emission factors for 
each fluorinated GHG and fluorinated GHG byproduct for the current year 
and the next 4 years with no further testing unless your fab operations 
are changed in a way that triggers the re-test criteria in paragraph 
(j)(8) of this section. In the fifth year following the last stack test 
included in the previous average, you must test each of the stack 
systems and repeat the relative standard deviation analysis using the 
results of the most recent three tests (i.e. , the new test and the two 
previous tests conducted prior to the 4-year period). If the criteria 
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are not 
met, you must use the emission factors developed from the most recent 
testing and continue annual testing. You may conduct more than one test 
in the same year, but each set of emissions testing for a stack system 
must be separated by a period of at least 2 months. You may repeat the 
relative standard deviation analysis using the most recent three tests, 
including those tests conducted prior to the 4-year period, to 
determine if you are exempt from testing for the next 4 years.
    (A) The relative standard deviation of the total CO2e 
emission factors calculated from each of the three tests (expressed as 
the total CO2e fluorinated GHG emissions of the fab divided 
by the total CO2e fluorinated GHG use of the fab) is less 
than or equal to 15 percent.
    (B) The relative standard deviation for all single fluorinated GHGs 
that individually accounted for 5 percent or more of CO2e 
emissions were less than 20 percent.
* * * * *

0
25. Amend Sec.  98.96 by:
0
a. Revising paragraphs (c)(1) and (2);
0
b. Adding paragraph (o); and
0
c. Revising paragraphs (p)(2), (q)(2) and (3), (r)(2), (w)(2), (y) 
introductory text, (y)(1), (y)(2)(i) and (iv), and (y)(4).
    The revisions and addition read as follows:


Sec.  98.96  Data reporting requirements.

* * * * *
    (c) * * *
    (1) When you use the procedures specified in Sec.  98.93(a), each 
fluorinated GHG emitted from each process type for which your fab is 
required to calculate emissions as calculated in equations I-6, I-7, 
and I-9 to Sec.  98.93.
    (2) When you use the procedures specified in Sec.  98.93(a), each 
fluorinated GHG emitted from each process type or process sub-type as 
calculated in equations I-8A and I-8B to Sec.  98.93, as applicable.
* * * * *
    (o) For all HC fuel CECS that were purchased and installed on or 
after January 1, 2025, that are used to control emissions from tools 
that use either NF3 as an input gas in remote plasma clean 
processes or F2 as an input gas in any process type or sub-
type and for which you are not calculating emissions under equation I-9 
to Sec.  98.93, certification that the rate of conversion from 
F2 to CF4 is <0.1% and that the systems are 
installed, operated, and maintained in accordance with the directions 
of the HC fuel CECS manufacturer. Hydrocarbon-fuel-based combustion 
emissions control systems include but are not limited to abatement 
systems as defined in Sec.  98.98 that are hydrocarbon-fuel-based. If 
you make the certification based on your own testing, you must certify 
that you tested the model of the system according to the requirements 
specified in Sec.  98.94(e). If you make the certification based on 
testing by the HC fuel CECS manufacturer, you must provide 
documentation from the HC fuel CECS manufacturer that the rate of 
conversion from F2 to CF4 is <0.1% when tested 
according to the requirements specified in Sec.  98.94(e).
    (p) * * *
    (2) The basis of the destruction or removal efficiency being used 
(default, manufacturer-verified, or site-specific measurement according 
to

[[Page 31916]]

Sec.  98.94(f)(4)(i)) for each process sub-type or process type and for 
each gas.
    (q) * * *
    (2) If you use default destruction or removal efficiency values in 
your emissions calculations under Sec.  98.93(a), (b), or (i), 
certification that the site maintenance plan for abatement systems for 
which emissions are being reported contains the manufacturer's 
recommendations and specifications for installation, operation, and 
maintenance for each abatement system. To use the default or lower 
manufacturer-verified destruction or removal efficiency values, 
operation of the abatement system must be within manufacturer's 
specifications, which may include, for example, specifications on 
vacuum pumps' purges, fuel and oxidizer settings, supply and exhaust 
flows and pressures, and utilities to the emissions control equipment 
including fuel gas flow and pressure, calorific value, and water 
quality, flow and pressure.
    (3) If you use default destruction or removal efficiency values in 
your emissions calculations under Sec.  98.93(a), (b), and/or (i), 
certification that the abatement systems for which emissions are being 
reported were specifically designed for fluorinated GHG or 
N2O abatement, as applicable. You must support this 
certification by providing abatement system supplier documentation 
stating that the system was designed for fluorinated GHG or 
N2O abatement, as applicable, and supply the destruction or 
removal efficiency value at which each abatement system is certified 
for the fluorinated GHG or N2O abated, as applicable. You 
may only use the default destruction or removal efficiency value if the 
abatement system is verified to meet or exceed the destruction or 
removal efficiency default value in table I-16 to this subpart. If the 
system is verified at a destruction or removal efficiency value lower 
than the default value, you may use the verified value.
* * * * *
    (r) * * *
    (2) Use equation I-28 to this section to calculate total unabated 
emissions, in metric ton CO2e, of all fluorinated GHG 
emitted from electronics manufacturing processes whose emissions of 
fluorinated GHG you calculated according to the stack testing 
procedures in Sec.  98.93(i)(3). For each set of processes, use the 
same input gas consumption (Cif), input gas emission factors 
(EFif), by-product gas emission factors (EFkf), 
fractions of tools abated (aif and akif), and 
destruction efficiencies (dif and dik) to 
calculate unabated emissions as you used to calculate emissions.
[GRAPHIC] [TIFF OMITTED] TR25AP24.033

Where:

SFGHG = Total unabated emissions of fluorinated GHG emitted from 
electronics manufacturing processes in the fab, expressed in metric 
ton CO2e for which you calculated total emission 
according to the procedures in Sec.  98.93(i)(3).
EFif = Emission factor for fluorinated GHG input gas i, 
emitted from fab f, as calculated in equation I-19 to Sec.  98.93 
(kg emitted/kg input gas consumed).
aif = Fraction of fluorinated GHG input gas i used in fab 
f in tools with abatement systems (expressed as a decimal fraction).
dif = Fraction of fluorinated GHG i destroyed or removed 
in abatement systems connected to process tools in fab f, as 
calculated from equation I-24A to Sec.  98.93, which you used to 
calculate total emissions according to the procedures in Sec.  
98.93(i)(3) (expressed as a decimal fraction).
Cif = Total consumption of fluorinated GHG input gas i, 
of tools vented to stack systems, for fab f, for the reporting year, 
expressed in metric ton CO2e, which you used to calculate 
total emissions according to the procedures in Sec.  98.93(i)(3) 
(expressed as a decimal fraction).
EFkf = Emission factor for fluorinated GHG by-product gas 
k, emitted from fab f, as calculated in equation I-20 to Sec.  98.93 
(kg emitted/kg of all input gases consumed in tools vented to stack 
systems).
akif = Fraction of fluorinated GHG by-product gas k 
emitted in fab f from tools using input gas i with abatement systems 
(expressed as a decimal fraction), as calculated using equation I-
24D to Sec.  98.93.
dik = Fraction of fluorinated GHG byproduct k destroyed 
or removed in abatement systems connected to process tools in fab f, 
as calculated from equation I-24B to Sec.  98.93, which you used to 
calculate total emissions according to the procedures in Sec.  
98.93(i)(3) (expressed as a decimal fraction).
GWPi = GWP of emitted fluorinated GHG i from table A-1 to 
subpart A of this part.
GWPk = GWP of emitted fluorinated GHG by-product k from 
table A-1 to subpart A of this part.
i = Fluorinated GHG.
k = Fluorinated GHG by-product.
* * * * *
    (w) * * *
    (2) An inventory of all stack systems from which process 
fluorinated GHG are emitted.
* * * * *
    (y) If your semiconductor manufacturing facility manufactures 
wafers greater than 150 mm and emits more than 40,000 metric ton 
CO2e of GHG emissions, based on your most recently submitted 
annual report as required in paragraph (c) of this section, from the 
electronics manufacturing processes subject to reporting under this 
subpart, you must prepare and submit a technology assessment report 
every five years to the Administrator (or an authorized representative) 
that meets the requirements specified in paragraphs (y)(1) through (6) 
of this section. Any other semiconductor manufacturing facility may 
voluntarily submit this report to the Administrator. If your 
semiconductor manufacturing facility manufactures only 150 mm or 
smaller wafers, you are not required to prepare and submit a technology 
assessment report, but you are required to prepare and submit a report 
if your facility begins manufacturing wafers 200 mm or larger during or 
before the calendar year preceding the year the technology assessment 
report is due. If your semiconductor manufacturing facility is no 
longer required to report to the GHGRP under subpart I due to the 
cessation of semiconductor manufacturing as described in Sec.  
98.2(i)(3), you are not required to submit a technology assessment 
report.
    (1) The first technology assessment report due after January 1, 
2025, is due on March 31, 2028, and subsequent reports must be 
delivered every 5 years no later than March 31 of the year in which it 
is due.
    (2) * * *
    (i) It must describe how the gases and technologies used in 
semiconductor manufacturing using 200 mm and 300 mm wafers in the 
United States have changed in the past 5 years and whether any of the 
identified changes are likely to have affected the emissions 
characteristics of semiconductor manufacturing processes in such a way 
that the default utilization and by-product formation rates or default 
destruction or removal efficiency factors of this subpart may need to 
be updated.
* * * * *

[[Page 31917]]

    (iv) It must provide any utilization and byproduct formation rates 
and/or destruction or removal efficiency data that have been collected 
in the previous 5 years that support the changes in semiconductor 
manufacturing processes described in the report. Any utilization or 
byproduct formation rate data submitted must be reported using both of 
the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this 
section if multiple fluorinated input gases are used, unless one of the 
input gases does not have a reference process utilization rate in table 
I-19 or I-20 to this subpart for the process type and wafer size whose 
emission factors are being measured, in which case the data must be 
submitted using the method specified in paragraph (y)(2)(iv)(A) of this 
section. If only one fluorinated input gas is fed into the process, you 
must use equations I-29A and I-29B to this section. In addition to 
using the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this 
section, you have the option to calculate and report the utilization or 
byproduct formation rate data using any alternative calculation 
methodology. The report must include the input gases used and measured, 
the utilization rates measured, the byproduct formation rates measured, 
the process type, the process subtype for chamber clean processes, the 
wafer size, and the methods used for the measurements. The report must 
also specify the method used to calculate each reported utilization and 
by-product formation rate, and provide a unique record number for each 
data set. For any destruction or removal efficiency data submitted, the 
report must include the input gases used and measured, the destruction 
and removal efficiency measured, the process type, the methods used for 
the measurements, and whether the abatement system is specifically 
designed to abate the gas measured under the operating conditions used 
for the measurement. If you choose to use an additional alternative 
calculation methodology to calculate and report the input gas emission 
factors and by-product formation rates, you must provide a complete, 
mathematical description of the alternative method used (including the 
equation used to calculate each reported utilization and by-product 
formation rate) and include the information in this paragraph 
(y)(2)(iv).
    (A) All-input gas method. Use equation I-29A to this section to 
calculate the input gas emission factor (1 - Uij) for each 
input gas in a single test. If the result of equation I-29A exceeds 0.8 
for an F-GHG that contains carbon, you must use equation I-29C to this 
section to calculate the input gas emission factor for that F-GHG and 
equation I-29D to this section to calculate the by-product formation 
rate for that F-GHG from the other input gases. Use equation I-29B to 
this section to calculate the by-product formation rates from each 
input gas for F-GHGs that are not input gases. If a test uses a 
cleaning or etching gas that does not contain carbon in combination 
with a cleaning or etching gas that does contain carbon and the process 
chamber is not used to etch or deposit carbon-containing films, you may 
elect to assign carbon containing by-products only to the carbon-
containing input gases. If you choose to assign carbon containing by-
products only to carbon-containing input gases, remove the input mass 
of the non-carbon containing gases from the sum of Massi and 
the sum of Massg in equations I-29B and I-29D to this 
section, respectively.
[GRAPHIC] [TIFF OMITTED] TR25AP24.034

Where:

Uij = Process utilization rate for fluorinated GHG i, 
process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the process.
i = Fluorinated GHG.
j = Process type.
[GRAPHIC] [TIFF OMITTED] TR25AP24.035

Where:

BEFkji = By-product formation rate for gas k from input 
gas i, for process type j, where gas k is not an input gas.
Ek = The mass emissions of by-product gas k.
Massi = The mass of input gas i fed into the process.
i = Fluorinated GHG.
j = Process type.
k = Fluorinated GHG by-product.
[GRAPHIC] [TIFF OMITTED] TR25AP24.036

Where:

Uij = Process utilization rate for fluorinated GHG i, 
process type j.
[GRAPHIC] [TIFF OMITTED] TR25AP24.037

Where:

BEFijg = By-product formation rate for gas i from input 
gas g for process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the process.
Massg = The mass of input gas g fed into the process, 
where g does not equal input gas i.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
j = Process type.

    (B) Reference emission factor method. Calculate the input gas 
emission factors and by-product formation rates from a test using 
equations I-30A, I-30B, and I-29B to this section, and table I-19 or I-
20 to this subpart. In this case, use

[[Page 31918]]

equation I-30A to this section to calculate the input gas emission 
factors and use equation I-30B and I-29B to this section to calculate 
the by-product formation rates.
[GRAPHIC] [TIFF OMITTED] TR25AP24.038

Where:

Uij = Process utilization rate for fluorinated GHG i, 
process type j.
Uijr = Reference process utilization rate for fluorinated 
GHG i, process type j, for input gas i, using table I-19 or I-20 to 
this subpart as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process, 
where g does not equal input gas i.
BEFijgr = Reference by-product formation rate for gas i 
from input gas g for process type j, using table I-19 or I-20 to 
this subpart as appropriate.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
[GRAPHIC] [TIFF OMITTED] TR25AP24.039

Where:

BEFijg = By-product formation rate for gas i from input 
gas g for process type j, where gas i is also an input gas.
BEFijgr = Reference by-product formation rate for gas i 
from input gas g for process type j from table I-19 or I-20 to this 
subpart, as appropriate.
Uijr = Reference process utilization rate for fluorinated 
GHG i, process type j, for input gas i, using table I-19 or I-20 to 
this subpart, as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process, 
where g does not equal input gas i.
i = Fluorinated GHG.
j = Process type.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
* * * * *
    (4) Multiple semiconductor manufacturing facilities may submit a 
single consolidated technology assessment report as long as the 
facility identifying information in Sec.  98.3(c)(1) and the 
certification statement in Sec.  98.3(c)(9) is provided for each 
facility for which the consolidated report is submitted.
* * * * *

0
26. Amend Sec.  98.97 by:
0
a. Adding paragraph (b);
0
b. Revising paragraphs (d)(1)(iii), (d)(3), (d)(5)(i), (d)(6) and (7), 
and (d)(9)(i);
0
c. Removing and reserving paragraph (i)(1); and
0
d. Revising paragraphs (i)(5) and (9) and (k).
    The addition and revisions read as follows:


Sec.  98.97  Records that must be retained.

* * * * *
    (b) If you use HC fuel CECS purchased and installed on or after 
January 1, 2025, to control emissions from tools that use either 
NF3 as an input gas in remote plasma cleaning processes or 
F2 as an input gas in any process, and if you use a value 
less than 1 for either aF2,j or aNF3,RPC in 
equation I-9 to Sec.  98.93, certification and documentation that the 
model for each of the systems that you claim does not form 
CF4 from F2 has been tested and verified to 
produce less than 0.1% CF4 from F2, and 
certification that the site maintenance plan includes the HC fuel CECS 
manufacturer's recommendations and specifications for installation, 
operation, and maintenance of those systems. If you are relying on your 
own testing to make the certification that the model produces less than 
0.1% CF4 from F2, the documentation must include 
the model tested, the method used to perform the testing (e.g., EPA 
430-R-10-003, modified to calculate the formation rate of 
CF4 from F2 rather than the DRE), complete 
documentation of the results of any initial and subsequent tests, and a 
final report similar to that specified in EPA 430-R-10-003 
(incorporated by reference, see Sec.  98.7), with appropriate 
adjustments to reflect the measurement of the formation rate of 
CF4 from F2 rather than the DRE. If you are 
relying on testing by the HC fuel CECS manufacturer to make the 
certification that the system produces less than 0.1% CF4 
from F2, the documentation must include the model tested, 
the method used to perform the testing, and the results of the test.
* * * * *
    (d) * * *
    (1) * * *
    (iii) If you use either default destruction or removal efficiency 
values or certified destruction or removal efficiency values that are 
lower than the default values in your emissions calculations under 
Sec.  98.93(a), (b), and/or (i), certification that the abatement 
systems for which emissions are being reported were specifically 
designed for fluorinated GHG and N2O abatement, as required 
under Sec.  98.94(f)(3), certification that the site maintenance plan 
includes the abatement system manufacturer's recommendations and 
specifications for installation, operation, and maintenance, and the 
certified destruction and removal efficiency values for all applicable 
abatement systems. For abatement systems purchased and installed on or 
after January 1, 2025, also include records of the method used to 
measure the destruction and removal efficiency values.
* * * * *
    (3) Where either the default destruction or removal efficiency 
value or a certified destruction or removal efficiency value that is 
lower than the default is used, documentation from the abatement system 
supplier describing the equipment's designed purpose and emission 
control capabilities for fluorinated GHG and N2O.
* * * * *
    (5) * * *
    (i) The number of abatement systems of each manufacturer, and model 
numbers, and the manufacturer's certified fluorinated GHG and 
N2O destruction or removal efficiency, if any.
* * * * *
    (6) Records of all inputs and results of calculations made 
accounting for the uptime of abatement systems used during the 
reporting year, in accordance with equations I-15 or I-23 to Sec.  
98.93, as applicable. The inputs should

[[Page 31919]]

include an indication of whether each value for destruction or removal 
efficiency is a default value, lower manufacturer-verified value, or a 
measured site-specific value.
    (7) Records of all inputs and results of calculations made to 
determine the average weighted fraction of each gas destroyed or 
removed in the abatement systems for each stack system using equations 
I-24A and I-24B to Sec.  98.93, if applicable. The inputs should 
include an indication of whether each value for destruction or removal 
efficiency is a default value, lower manufacturer-verified value, or a 
measured site-specific value.
* * * * *
    (9) * * *
    (i) The site maintenance plan for abatement systems must be based 
on the abatement system manufacturer's recommendations and 
specifications for installation, operation, and maintenance if you use 
default or lower manufacturer-verified destruction and removal 
efficiency values in your emissions calculations under Sec.  98.93(a), 
(b), and/or (i). If the manufacturer's recommendations and 
specifications for installation, operation, and maintenance are not 
available, you cannot use default destruction and removal efficiency 
values or lower manufacturer-verified value in your emissions 
calculations under Sec.  98.93(a), (b), and/or (i). If you use an 
average of properly measured destruction or removal efficiencies 
determined in accordance with the procedures in Sec.  98.94(f)(4)(i) 
through (vi), the site maintenance plan for abatement systems must be 
based on the abatement system manufacturer's recommendations and 
specifications for installation, operation, and maintenance, where 
available. If you deviate from the manufacturer's recommendations and 
specifications, you must include documentation that demonstrates how 
the deviations do not negatively affect the performance or destruction 
or removal efficiency of the abatement systems.
* * * * *
    (i) * * *
    (5) The fab-specific emission factor and the calculations and data 
used to determine the fab-specific emission factor for each fluorinated 
GHG and by-product, as calculated using equations I-19A, I-19B, I-19C 
and I-20 to Sec.  98.93(i)(3).
* * * * *
    (9) The number of tools vented to each stack system in the fab and 
all inputs and results for the calculations accounting for the fraction 
of gas exhausted through abatement systems using equations I-24C and I-
24D to Sec.  98.93.
* * * * *
    (k) Annual gas consumption for each fluorinated GHG and 
N2O as calculated in equation I-11 to Sec.  98.93, including 
where your fab used less than 50 kg of a particular fluorinated GHG or 
N2O used at your facility for which you have not calculated 
emissions using equations I-6, I-7, I-8A, I-8B, I-9, I-10, I-21, or I-
22 to Sec.  98.93, the chemical name of the GHG used, the annual 
consumption of the gas, and a brief description of its use.
* * * * *

0
27. Amend Sec.  98.98 by:
0
a. Removing the definition ``Fluorinated heat transfer fluids'';
0
b. Adding the definition ``Hydrocarbon-fuel based combustion emission 
control systems (HC fuel CECs)'' in alphabetical order; and
0
c. Revising the definition ``Operational mode''.
    The revisions and addition read as follows:


Sec.  98.98  Definitions.

* * * * *
    Hydrocarbon-fuel based combustion emission control system (HC fuel 
CECS) means a hydrocarbon fuel-based combustion device or equipment 
that is designed to destroy or remove gas emissions in exhaust streams 
via combustion from one or more electronics manufacturing production 
processes, and that is connected to manufacturing tools that have the 
potential to emit F2 or fluorinated greenhouse gases. HC 
fuel CECs include both emission control systems that are and are not 
designed to destroy or remove fluorinated GHGs or N2O.
* * * * *
    Operational mode means the time in which an abatement system is 
properly installed, maintained, and operated according to the site 
maintenance plan for abatement systems as required in Sec.  98.94(f)(1) 
and defined in Sec.  98.97(d)(9). This includes being properly operated 
within the range of parameters as specified in the site maintenance 
plan for abatement systems. For abatement systems purchased and 
installed on or after January 1, 2025, this includes being properly 
operated within the range of parameters specified in the DRE 
certification documentation. An abatement system is considered to not 
be in operational mode when it is not operated and maintained according 
to the site maintenance plan for abatement systems or, for abatement 
systems purchased and installed on or after January 1, 2025, not 
operated within the range of parameters as specified in the DRE 
certification documentation.
* * * * *

0
28. Revise table I-1 to subpart I to read as follows:

           Table I-1 to Subpart I of Part 98--Default Emission Factors for Manufacturing Capacity-Based Threshold Applicability Determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                               Emission factors EFi
                                                        ------------------------------------------------------------------------------------------------
                      Product type                                                              c-C4F8
                                                            CF4         C2F6         CHF3                      C3F8         NF3        SF6        N2O
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiconductors (kg/m\2\)...............................        0.9          1.0        0.04           NA          0.05        0.04       0.20         NA
LCD (g/m\2\)...........................................       0.65           NA      0.0024         0.00            NA        1.29       4.14      17.06
MEMS (kg/m\2\).........................................      0.015           NA          NA        0.076            NA          NA       1.86         NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.



0
29. Revise table I-2 to subpart I to read as follows:

[[Page 31920]]



  Table I-2 to Subpart I of Part 98--Default Emission Factors for Gas Consumption-Based Threshold Applicability
                                                  Determination
----------------------------------------------------------------------------------------------------------------
                                                                                       Process gas i
                                                                         ---------------------------------------
                                                                           Fluorinated GHGs           N2O
----------------------------------------------------------------------------------------------------------------
1-Ui....................................................................                 0.8                   1
BCF4....................................................................                0.15                   0
BC2F6...................................................................                0.05                   0
----------------------------------------------------------------------------------------------------------------


0
30. Revise table I-3 to subpart I to read as follows:

 Table I-3 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200 mm
                                                                                           Wafer Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Process gas i
     Process type/sub-type     -----------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  CF4        C2F6        CHF3        CH2F2          C2HF5        CH3F        C3F8          C4F8        NF3      SF6        C4F6          C5F8          C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................     0.73        0.72        0.51        0.13          0.064         0.70          NA          0.14       0.19     0.55       0.083         0.072              NA
BCF4..........................       NA        0.10       0.085       0.079          0.077           NA          NA          0.11     0.0040     0.13       0.095            NA              NA
BC2F6.........................    0.041          NA       0.035       0.025          0.024       0.0034          NA         0.037      0.025     0.11       0.073         0.014              NA
BC4F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BCHF3.........................    0.091       0.047          NA       0.049             NA           NA          NA         0.040         NA   0.0012       0.066        0.0039              NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................     0.92        0.55          NA          NA             NA           NA        0.40          0.10       0.18       NA          NA            NA            0.14
BCF4..........................       NA        0.19          NA          NA             NA           NA        0.20          0.11       0.14       NA          NA            NA            0.13
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA           0.045
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................       NA          NA          NA          NA             NA           NA          NA            NA      0.028       NA          NA            NA              NA
BCF4..........................       NA          NA          NA          NA             NA           NA          NA            NA      0.015       NA          NA            NA              NA
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BF2...........................       NA          NA          NA          NA             NA           NA          NA            NA        0.5       NA          NA            NA              NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BCF4..........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA              NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
  from a particular process sub-type or process type.

    31. Revise table I-4 to subpart I to read as follows:

 Table I-4 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm and 450 mm
                                                                                           Wafer Size
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                               Process gas i
          Process type/sub-type           ------------------------------------------------------------------------------------------------------------------------------------------------------
                                             CF4        C2F6        CHF3        CH2F2        CH3F        C3F8          C4F8         NF3        SF6         C4F6          C5F8          C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.....................................     0.65        0.80        0.37        0.20         0.30         0.30         0.18         0.16       0.30         0.15          0.10            NA
BCF4.....................................       NA        0.21       0.076       0.060       0.0291         0.21        0.045        0.044      0.033        0.059          0.11            NA
BC2F6....................................    0.058          NA       0.058       0.043        0.009        0.018        0.027        0.045      0.041        0.062         0.083            NA
BC4F8....................................   0.0046          NA      0.0027       0.054       0.0070           NA           NA           NA         NA       0.0051            NA            NA
BC3F8....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA       0.00012            NA
BCHF3....................................    0.012          NA          NA       0.057        0.016        0.012        0.028        0.023     0.0039        0.017        0.0069            NA
BCH2F2...................................    0.005          NA      0.0024          NA       0.0033           NA       0.0021      0.00074   0.000020     0.000030            NA            NA
BCH3F....................................   0.0061          NA       0.027      0.0036           NA      0.00073       0.0063       0.0080     0.0082      0.00065            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 31921]]

 
                                                                                        Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.....................................       NA          NA          NA          NA           NA           NA           NA         0.20         NA           NA            NA            NA
BCF4.....................................       NA          NA          NA          NA           NA           NA           NA        0.037         NA           NA            NA            NA
BC2F6....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
BC3F8....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.....................................       NA          NA          NA          NA           NA        0.063           NA        0.018         NA           NA            NA            NA
BCF4.....................................       NA          NA          NA          NA           NA           NA           NA        0.037         NA           NA            NA            NA
BC2F6....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
BC3F8....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
BCHF3....................................       NA          NA          NA          NA           NA           NA           NA     0.000059         NA           NA            NA            NA
BCH2F2...................................       NA          NA          NA          NA           NA           NA           NA      0.00088         NA           NA            NA            NA
BCH3F....................................       NA          NA          NA          NA           NA           NA           NA       0.0028         NA           NA            NA            NA
BF2......................................       NA          NA          NA          NA           NA           NA           NA          0.5         NA           NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.....................................       NA          NA          NA          NA           NA           NA           NA         0.28         NA           NA            NA            NA
BCF4.....................................       NA          NA          NA          NA           NA           NA           NA        0.010         NA           NA            NA            NA
BC2F6....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
BC3F8....................................       NA          NA          NA          NA           NA           NA           NA           NA         NA           NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
  from a particular process sub-type or process type.


0
32. Revise table I-8 to subpart I to read as follows:

 Table I-8 to Subpart I of Part 98--Default Emission Factors (1-UN2O,j)
                      for N2O Utilization (UN2O,j)
------------------------------------------------------------------------
       Manufacturing type/process type/wafer size               N2O
------------------------------------------------------------------------
Semiconductor Manufacturing:
    200 mm or Less:
        CVD 1-Ui........................................             1.0
        Other Manufacturing Process 1-Ui................             1.0
    300 mm or greater:
        CVD 1-Ui........................................             0.5
        Other Manufacturing Process 1-Ui................             1.0
LCD Manufacturing:
    CVD Thin Film Manufacturing 1-Ui....................            0.63
All other N2O Processes.................................             1.0
------------------------------------------------------------------------


0
33. Revise table I-11 to subpart I to read as follows:

              Table I-11 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
                                                                                                       [150 mm and 200 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Process gas i
                                                         -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                      All processes                                                                                                                                            NF3
                                                             CF4        C2F6        CHF3        CH2F2          C2HF5          CH3F         C3F8          C4F8        NF3     Remote     SF6        C4F6          C5F8          C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui....................................................      0.79        0.55        0.51        0.13          0.064            0.70       0.40           0.12       0.18     0.028     0.58      0.083           0.072          0.14
BCF4....................................................        NA        0.19       0.085       0.079          0.077              NA       0.20           0.11       0.11     0.015     0.13      0.095              NA          0.13
BC2F6...................................................     0.027          NA       0.035       0.025          0.024          0.0034         NA          0.019     0.0059        NA     0.10      0.073           0.014         0.045
BC4F8...................................................        NA          NA          NA          NA             NA              NA         NA             NA         NA        NA       NA         NA              NA            NA
BC3F8...................................................        NA          NA          NA          NA             NA              NA         NA             NA         NA        NA       NA         NA              NA            NA
BC5F8...................................................   0.00077          NA      0.0012          NA             NA              NA         NA         0.0043         NA        NA       NA         NA              NA            NA
BCHF3...................................................     0.060      0.0020          NA       0.049             NA              NA         NA          0.020         NA        NA   0.0011      0.066          0.0039            NA
BF2.....................................................        NA          NA          NA          NA             NA              NA         NA             NA         NA      0.50       NA         NA              NA            NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type.


[[Page 31922]]



0
34. Revise table I-12 to subpart I to read as follows:

              Table I-12 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
                                                                                                       [300 mm and 450 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Process gas i
                                                          ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                      All processes                                                                                                 C3F8 Remote                             NF3
                                                             CF4        C2F6        CHF3        CH2F2        CH3F        C3F8                        C4F8         NF3      Remote      SF6         C4F6          C5F8          C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.....................................................     0.65       0.80         0.37        0.20         0.30        0.30         0.063         0.183        0.19      0.018       0.30         0.15         0.100           NA
BCF4.....................................................       NA       0.21        0.076       0.060        0.029        0.21            NA         0.045       0.040      0.037      0.033        0.059         0.109           NA
BC2F6....................................................    0.058         NA        0.058       0.043       0.0093        0.18            NA         0.027      0.0204         NA      0.041        0.062         0.083           NA
BC4F6....................................................   0.0083         NA      0.01219          NA        0.001          NA            NA         0.008          NA         NA         NA           NA            NA           NA
BC4F8....................................................   0.0046         NA      0.00272       0.054        0.007          NA            NA            NA          NA         NA         NA       0.0051            NA           NA
BC3F8....................................................       NA         NA           NA          NA           NA          NA            NA            NA          NA         NA         NA           NA       0.00012           NA
BCH2F2...................................................    0.005         NA       0.0024          NA       0.0033          NA            NA        0.0021     0.00034    0.00088   0.000020     0.000030            NA           NA
BCH3F....................................................   0.0061         NA        0.027      0.0036           NA      0.0007            NA        0.0063      0.0036     0.0028     0.0082      0.00065            NA           NA
BCHF3....................................................    0.012         NA           NA       0.057        0.016       0.012            NA         0.028      0.0106   0.000059     0.0039        0.017        0.0069           NA
BF2......................................................       NA         NA           NA          NA           NA          NA            NA            NA          NA       0.50         NA           NA            NA           NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


0
35. Revise table I-16 to subpart I to read as follows:

   Table I-16 to Subpart I of Part 98--Default Emission Destruction or
     Removal Efficiency (DRE) Factors for Electronics Manufacturing
------------------------------------------------------------------------
                                                            Default DRE
           Manufacturing type/process type/gas                  (%)
------------------------------------------------------------------------
MEMS, LCDs, and PV Manufacturing........................              60
Semiconductor Manufacturing:
    CF4.................................................              87
    CH3F................................................              98
    CHF3................................................              97
    CH2F2...............................................              98
    C4F8................................................              93
    C4F8O...............................................              93
    C5F8................................................              97
    C4F6................................................              95
    C3F8................................................              98
    C2HF5...............................................              97
    C2F6................................................              98
    SF6.................................................              95
    NF3.................................................              96
All other carbon-based fluorinated GHGs used in                       60
 Semiconductor Manufacturing............................
N2O Processes...........................................
CVD and all other N2O-using processes...................              60
------------------------------------------------------------------------


0
36. Add table I-18 to subpart I to read as follows:

 Table I-18 to Subpart I of Part 98--Default Factors for Gamma (gi,p and gk,i,p) for Semiconductor Manufacturing and for MEMS and PV Manufacturing Under
                                               Certain Conditions * for Use With the Stack Testing Method
--------------------------------------------------------------------------------------------------------------------------------------------------------
                      Process type                                In-situ thermal or in-situ plasma cleaning                Remote plasma cleaning
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     c-C4F8
                          Gas                               CF4         C2F6                       NF3        SF6         C3F8         CF4        NF3
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                 If manufacturing wafer sizes <=200 mm AND manufacturing 300 mm (or greater) wafer sizes
--------------------------------------------------------------------------------------------------------------------------------------------------------
gi.....................................................         13          9.3           4.7          14         11           NA          NA        5.7
gCF4,i.................................................         NA           23           6.7          63        8.7           NA          NA         58
gC2F6,i................................................         NA           NA            NA          NA        3.4           NA          NA         NA
gCHF3,i................................................         NA           NA            NA          NA         NA           NA          NA       0.24
gCH2F2,i...............................................         NA           NA            NA          NA         NA           NA          NA        111
gCH3F,i................................................         NA           NA            NA          NA         NA           NA          NA         33
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                       If manufacturing <=200 mm OR manufacturing 300 mm (or greater) wafer sizes
--------------------------------------------------------------------------------------------------------------------------------------------------------
gi (<= 200 mm wafer size)..............................         13          9.3           4.7         2.9         11           NA          NA        1.4

[[Page 31923]]

 
gCF4,i (<=200 mm wafer size)...........................         NA           23           6.7         110        8.7           NA          NA         36
gC2F6,i (<=200 mm wafer size)..........................         NA           NA            NA          NA        3.4           NA          NA         NA
gi (300 mm wafer size).................................         NA           NA            NA          26         NA           NA          NA         10
gCF4,i (300 mm wafer size).............................         NA           NA            NA          17         NA           NA          NA         80
gC2F6,i (300 mm wafer size)............................         NA           NA            NA          NA         NA           NA          NA         NA
gCHF3,i (300 mm wafer size)............................         NA           NA            NA          NA         NA           NA          NA       0.24
gCH2F2,i (300 mm wafer size)...........................         NA           NA            NA          NA         NA           NA          NA        111
gCH3F,i (300 mm wafer size)............................         NA           NA            NA          NA         NA           NA          NA         33
--------------------------------------------------------------------------------------------------------------------------------------------------------
* If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use the corresponding g in this table. For all other tools and
  processes, a default g of 10 must be used.


0
37. Add table I-19 to subpart I to read as follows:

 Table I-19 to Subpart I of Part 98--Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200
                                                                                         mm Wafer Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                          Process gas i
     Process type/sub-type     -----------------------------------------------------------------------------------------------------------------------------------------------------------------
                                  CF4        C2F6        CHF3        CH2F2          C2HF5        CH3F        C3F8          C4F8        NF3      SF6        C4F6          C5F8          C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................     0.73        0.46        0.31        0.37          0.064         0.66          NA          0.21       0.20     0.55       0.086         0.072            NA
BCF4..........................       NA        0.20        0.10       0.031          0.077           NA          NA          0.17     0.0040    0.023      0.0089            NA            NA
BC2F6.........................    0.029          NA          NA          NA             NA           NA          NA         0.065         NA       NA       0.045         0.014            NA
BC4F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC4F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC5F8.........................       NA          NA          NA          NA             NA           NA          NA         0.016         NA       NA          NA            NA            NA
BCHF3.........................     0.13          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA        0.0039            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................     0.92        0.55          NA          NA             NA           NA        0.40          0.10       0.18       NA          NA            NA          0.14
BCF4..........................       NA        0.19          NA          NA             NA           NA        0.20          0.11       0.14       NA          NA            NA          0.13
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA         0.045
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................       NA          NA          NA          NA             NA           NA          NA            NA      0.028       NA          NA            NA            NA
BCF4..........................       NA          NA          NA          NA             NA           NA          NA            NA      0.015       NA          NA            NA            NA
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BCF4..........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC2F6.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
BC3F8.........................       NA          NA          NA          NA             NA           NA          NA            NA         NA       NA          NA            NA            NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


0
38. Add table I-20 to subpart I to read as follows:

[[Page 31924]]



  Table I-20 to Subpart I of Part 98--Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm Wafer
                                                                                              Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                           Process gas i
      Process type/sub-type       --------------------------------------------------------------------------------------------------------------------------------------------------------------
                                      CF4        C2F6          CHF3         CH2F2        CH3F        C3F8          C4F8          NF3          SF6          C4F6          C5F8          C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.............................      0.68        0.80           0.35         0.15        0.34          0.30        0.16           0.17         0.28          0.17        0.10             NA
BCF4.............................        NA        0.21          0.073        0.020       0.038          0.21       0.045          0.035       0.0072         0.034        0.11             NA
BC2F6............................     0.041          NA          0.040       0.0065      0.0064          0.18       0.030          0.038       0.0017         0.025       0.083             NA
BC4F6............................    0.0015          NA        0.00010           NA      0.0010            NA     0.00083             NA           NA            NA          NA             NA
BC4F8............................    0.0051          NA        0.00061           NA      0.0070            NA          NA             NA           NA            NA          NA             NA
BC3F8............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA     0.00012             NA
BC5F8............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
BCHF3............................    0.0056          NA             NA        0.033      0.0049         0.012       0.029         0.0065       0.0012         0.019      0.0069             NA
BCH2F2...........................     0.014          NA         0.0026           NA      0.0023            NA      0.0014        0.00086     0.000020      0.000030          NA             NA
BCH3F............................   0.00057          NA           0.12           NA          NA       0.00073          NA             NA       0.0082            NA          NA             NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.............................        NA          NA             NA           NA          NA            NA          NA           0.20           NA            NA          NA             NA
BCF4.............................        NA          NA             NA           NA          NA            NA          NA          0.037           NA            NA          NA             NA
BC2F6............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
BC3F8............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.............................        NA          NA             NA           NA          NA         0.063          NA          0.018           NA            NA          NA             NA
BCF4.............................        NA          NA             NA           NA          NA            NA          NA          0.038           NA            NA          NA             NA
BC2F6............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
BC3F8............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
BCHF3............................        NA          NA             NA           NA          NA            NA          NA       0.000059           NA            NA          NA             NA
BCH2F2...........................        NA          NA             NA           NA          NA            NA          NA         0.0016           NA            NA          NA             NA
BCH3F............................        NA          NA             NA           NA          NA            NA          NA         0.0028           NA            NA          NA             NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                    In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.............................        NA          NA             NA           NA          NA            NA          NA           0.28           NA            NA          NA             NA
BCF4.............................        NA          NA             NA           NA          NA            NA          NA          0.010           NA            NA          NA             NA
BC2F6............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
BC3F8............................        NA          NA             NA           NA          NA            NA          NA             NA           NA            NA          NA             NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 31925]]


0
39. Add table I-21 to subpart I to read as follows:

Table I-21 to Subpart I of Part 98--Examples of Fluorinated GHGs Used by
                        the Electronics Industry
------------------------------------------------------------------------
                                        Fluorinated GHGs used during
           Product type                          manufacture
------------------------------------------------------------------------
Electronics.......................  CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
                                     C4F6, C5F8, CHF3, CH2F2, NF3, SF6,
                                     and fluorinated HTFs (CF3-(O-
                                     CF(CF3)-CF2)n-(O-CF2)m-O-CF3,
                                     CnF2n+2, CnF2n+1(O)CmF2m+1, CnF2nO,
                                     (CnF2n+1)3N).
------------------------------------------------------------------------

Subpart N--Glass Production

0
40. Revise and republish Sec.  98.146 to read as follows:


Sec.  98.146  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology and the following 
information specified in paragraphs (a)(1) through (3) of this section:
    (1) Annual quantity of each carbonate-based raw material (tons) 
charged to each continuous glass melting furnace and for all furnaces 
combined.
    (2) Annual quantity of glass produced (tons), by glass type, from 
each continuous glass melting furnace and from all furnaces combined.
    (3) Annual quantity (tons), by glass type, of recycled scrap glass 
(cullet) charged to each continuous glass melting furnace and for all 
furnaces combined.
    (b) If a CEMS is not used to determine CO2 emissions 
from continuous glass melting furnaces, and process CO2 
emissions are calculated according to the procedures specified in Sec.  
98.143(b), then you must report the following information as specified 
in paragraphs (b)(1) through (9) of this section:
    (1) Annual process emissions of CO2 (metric tons) for 
each continuous glass melting furnace and for all furnaces combined.
    (2) Annual quantity of each carbonate-based raw material charged 
(tons) to all furnaces combined.
    (3) Annual quantity of glass produced (tons), by glass type, from 
each continuous glass melting furnace and from all furnaces combined.
    (4) Annual quantity (tons), by glass type, of recycled scrap glass 
(cullet) charged to each continuous glass melting furnace and for all 
furnaces combined.
    (5) Results of all tests, if applicable, used to verify the 
carbonate-based mineral mass fraction for each carbonate-based raw 
material charged to a continuous glass melting furnace, as specified in 
paragraphs (b)(5)(i) through (iii) of this section.
    (i) Date of test.
    (ii) Method(s) and any variations used in the analyses.
    (iii) Mass fraction of each sample analyzed.
    (6) [Reserved]
    (7) Method used to determine decimal fraction of calcination, 
unless you used the default value of 1.0.
    (8) Total number of continuous glass melting furnaces.
    (9) The number of times in the reporting year that missing data 
procedures were followed to measure monthly quantities of carbonate-
based raw materials, recycled scrap glass (cullet), or mass fraction of 
the carbonate-based minerals for any continuous glass melting furnace 
(months).

0
41. Amend Sec.  98.147 by revising and republishing paragraphs (a) and 
(b) to read as follows:


Sec.  98.147  Records that must be retained.

* * * * *
    (a) If a CEMS is used to measure emissions, then you must retain 
the records required under Sec.  98.37 for the Tier 4 Calculation 
Methodology and the following information specified in paragraphs 
(a)(1) through (3) of this section:
    (1) Monthly glass production rate for each continuous glass melting 
furnace, by glass type (tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (tons).
    (3) Monthly amount (tons) of recycled scrap glass (cullet) charged 
to each continuous glass melting furnace, by glass type.
    (b) If process CO2 emissions are calculated according to 
the procedures specified in Sec.  98.143(b), you must retain the 
records in paragraphs (b)(1) through (6) of this section.
    (1) Monthly glass production rate for each continuous glass melting 
furnace, by glass type (tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (tons).
    (3) Monthly amount (tons) of recycled scrap glass (cullet) charged 
to each continuous glass melting furnace, by glass type.
    (4) Data on carbonate-based mineral mass fractions provided by the 
raw material supplier for all raw materials consumed annually and 
included in calculating process emissions in equation N-1 to Sec.  
98.143, if applicable.
    (5) Results of all tests, if applicable, used to verify the 
carbonate-based mineral mass fraction for each carbonate-based raw 
material charged to a continuous glass melting furnace, including the 
data specified in paragraphs (b)(5)(i) through (v) of this section.
    (i) Date of test.
    (ii) Method(s), and any variations of the methods, used in the 
analyses.
    (iii) Mass fraction of each sample analyzed.
    (iv) Relevant calibration data for the instrument(s) used in the 
analyses.
    (v) Name and address of laboratory that conducted the tests.
    (6) The decimal fraction of calcination achieved for each 
carbonate-based raw material, if a value other than 1.0 is used to 
calculate process mass emissions of CO2.
* * * * *

Subpart P--Hydrogen Production

0
42. Revise Sec.  98.160 to read as follows:


Sec.  98.160  Definition of the source category.

    (a) A hydrogen production source category consists of facilities 
that produce hydrogen gas as a product.
    (b) This source category comprises process units that produce 
hydrogen by reforming, gasification, oxidation, reaction, or other 
transformations of feedstocks except the processes listed in paragraph 
(b)(1) or (2) of this section.
    (1) Any process unit for which emissions are reported under another 
subpart of this part. This includes, but is not necessarily limited to:
    (i) Ammonia production units for which emissions are reported under 
subpart G.
    (ii) Catalytic reforming units at petroleum refineries that 
transform

[[Page 31926]]

naphtha into higher octane aromatics for which emissions are reported 
under subpart Y.
    (iii) Petrochemical process units for which emissions are reported 
under subpart X.
    (2) Any process unit that only separates out diatomic hydrogen from 
a gaseous mixture and is not associated with a unit that produces 
hydrogen created by transformation of one or more feedstocks, other 
than those listed in paragraph (b)(1) of this section.
    (c) This source category includes the process units that produce 
hydrogen and stationary combustion units directly associated with 
hydrogen production (e.g. , reforming furnace and hydrogen production 
process unit heater).

0
43. Amend Sec.  98.162 by revising paragraph (a) to read as follows:


Sec.  98.162  GHGs to report.

* * * * *
    (a) CO2 emissions from each hydrogen production process 
unit, including fuel combustion emissions accounted for in the 
calculation methodologies in Sec.  98.163.
* * * * *

0
44. Amend Sec.  98.163 by revising the introductory text, paragraph (b) 
introductory text, and paragraph (c) to read as follows:


Sec.  98.163  Calculating GHG emissions.

    You must calculate and report the annual CO2 emissions 
from each hydrogen production process unit using the procedures 
specified in paragraphs (a) through (c) of this section, as applicable.
* * * * *
    (b) Fuel and feedstock material balance approach. Calculate and 
report CO2 emissions as the sum of the annual emissions 
associated with each fuel and feedstock used for each hydrogen 
production process unit by following paragraphs (b)(1) through (3) of 
this section. The carbon content and molecular weight shall be obtained 
from the analyses conducted in accordance with Sec.  98.164(b)(2), (3), 
or (4), as applicable, or from the missing data procedures in Sec.  
98.165. If the analyses are performed annually, then the annual value 
shall be used as the monthly average. If the analyses are performed 
more frequently than monthly, use the arithmetic average of values 
obtained during the month as the monthly average.
* * * * *
    (c) If GHG emissions from a hydrogen production process unit are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part, then the owner or operator shall report under this subpart the 
combined stack emissions according to the Tier 4 Calculation 
Methodology in Sec.  98.33(a)(4) and all associated requirements for 
Tier 4 in subpart C of this part. If GHG emissions from a hydrogen 
production process unit using a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part does not include 
combustion emissions from the hydrogen production unit (i.e. , the 
hydrogen production unit has separate stacks for process and combustion 
emissions), then the calculation methodology in paragraph (b) of this 
section shall be used considering only fuel inputs to calculate and 
report CO2 emissions from fuel combustion related to the 
hydrogen production unit.

0
45. Amend Sec.  98.164 by:
0
a. Revising the introductory text, paragraphs (b)(2) through (4), and 
(b)(5) introductory text; and
0
b. Adding paragraphs (b)(5)(xix) and (c).
    The revisions and additions read as follows:


Sec.  98.164   Monitoring and QA/QC requirements.

    The GHG emissions data for hydrogen production process units must 
be quality-assured as specified in paragraph (a) or (b) of this 
section, as appropriate for each process unit, except as provided in 
paragraph (c) of this section:
* * * * *
    (b) * * *
    (2) Determine the carbon content and the molecular weight annually 
of standard gaseous hydrocarbon fuels and feedstocks having consistent 
composition (e.g., natural gas) according to paragraph (b)(5) of this 
section. For gaseous fuels and feedstocks that have a maximum product 
specification for carbon content less than or equal to 0.00002 kg 
carbon per kg of gaseous fuel or feedstock, you may instead determine 
the carbon content and the molecular weight annually using the product 
specification's maximum carbon content and molecular weight. For other 
gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process 
gas), sample and analyze no less frequently than weekly to determine 
the carbon content and molecular weight of the fuel and feedstock 
according to paragraph (b)(5) of this section.
    (3) Determine the carbon content of fuel oil, naphtha, and other 
liquid fuels and feedstocks at least monthly, except annually for 
standard liquid hydrocarbon fuels and feedstocks having consistent 
composition, or upon delivery for liquid fuels and feedstocks delivered 
by bulk transport (e.g., by truck or rail) according to paragraph 
(b)(5) of this section. For liquid fuels and feedstocks that have a 
maximum product specification for carbon content less than or equal to 
0.00006 kg carbon per gallon of liquid fuel or feedstock, you may 
instead determine the carbon content annually using the product 
specification's maximum carbon content.
    (4) Determine the carbon content of coal, coke, and other solid 
fuels and feedstocks at least monthly, except annually for standard 
solid hydrocarbon fuels and feedstocks having consistent composition, 
or upon delivery for solid fuels and feedstocks delivered by bulk 
transport (e.g., by truck or rail) according to paragraph (b)(5) of 
this section.
    (5) Except as provided in paragraphs (b)(2) and (3) of this section 
for fuels and feedstocks with a carbon content below the specified 
levels, you must use the following applicable methods to determine the 
carbon content for all fuels and feedstocks, and molecular weight of 
gaseous fuels and feedstocks. Alternatively, you may use the results of 
chromatographic analysis of the fuel and feedstock, provided that the 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions; and the methods used for operation, 
maintenance, and calibration of the chromatograph are documented in the 
written monitoring plan for the unit under Sec.  98.3(g)(5).
* * * * *
    (xix) For fuels and feedstocks with a carbon content below the 
specified levels in paragraphs (b)(2) and (3) of this section, if the 
methods listed in paragraphs (b)(5)(i) through (xviii) of this section 
are not appropriate because the relevant compounds cannot be detected, 
the quality control requirements are not technically feasible, or use 
of the method would be unsafe, you may use modifications of the methods 
listed in paragraphs (b)(5)(i) through (xviii) or use other methods 
that are applicable to your fuel or feedstock.
    (c) You may use best available monitoring methods as specified in 
paragraph (c)(2) of this section for measuring the fuel used by each 
stationary combustion unit directly associated with hydrogen production 
(e.g., reforming furnace and hydrogen production process unit heater) 
that

[[Page 31927]]

meets the criteria specified in paragraph (c)(1) of this section. 
Eligibility to use best available monitoring methods ends upon the 
completion of any planned process unit or equipment shutdown after 
January 1, 2025.
    (1) To be eligible to use best available monitoring methods, you 
must meet all criteria in paragraphs (c)(1)(i) through (iv) of this 
section.
    (i) The stationary combustion unit must be directly associated with 
hydrogen production (e.g., reforming furnace and hydrogen production 
process unit heater).
    (ii) A measurement device meeting the requirements in paragraph 
(b)(1) of this section is not installed to measure the fuel used by 
each stationary combustion unit as of January 1, 2025.
    (iii) The hydrogen production unit and associated stationary 
combustion unit are operated continuously.
    (iv) Installation of a measurement device to measure the fuel used 
by each stationary combustion unit that meets the requirements in 
paragraph (b)(1) of this section must require a planned process 
equipment or unit shutdown or can only be done through a hot tap.
    (2) Best available monitoring methods means any of the following 
methods:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of this subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.

0
46. Revise Sec.  98.166 to read as follows:


Sec.  98.166  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each hydrogen 
production process unit:
    (a) The unit identification number.
    (b) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec.  98.36 for the 
Tier 4 Calculation Methodology. If the CEMS measures emissions from 
either a common stack for multiple hydrogen production units or a 
common stack for hydrogen production unit(s) and other source(s), you 
must also report the estimated decimal fraction of the total annual 
CO2 emissions attributable to this hydrogen production 
process unit (estimated using engineering estimates or best available 
data).
    (c) If a material balance is used to calculate emissions using 
equations P-1 through P-3 to Sec.  98.163, as applicable, report the 
total annual CO2 emissions (metric tons) and the name and 
annual quantity (metric tons) of each carbon-containing fuel and 
feedstock.
    (d) The information specified in paragraphs (d)(1) through (10):
    (1) The type of hydrogen production unit (steam methane reformer 
(SMR) only, SMR followed by water gas shift reaction (WGS), partial 
oxidation (POX) only, POX followed by WGS, autothermal reforming only, 
autothermal reforming followed by WGS, water electrolysis, brine 
electrolysis, other (specify)).
    (2) The type of hydrogen purification method (pressure swing 
adsorption, amine adsorption, membrane separation, other (specify), 
none).
    (3) Annual quantity of hydrogen produced by reforming, 
gasification, oxidation, reaction, or other transformation of 
feedstocks (metric tons).
    (4) Annual quantity of hydrogen that is purified only (metric 
tons). This quantity may be assumed to be equal to the annual quantity 
of hydrogen in the feedstocks to the hydrogen production unit.
    (5) Annual quantity of ammonia intentionally produced as a desired 
product, if applicable (metric tons).
    (6) Quantity of CO2 collected and transferred off site 
in either gas, liquid, or solid forms, following the requirements of 
subpart PP of this part.
    (7) Annual quantity of carbon other than CO2 or methanol 
collected and transferred off site or transferred to a separate process 
unit within the facility for which GHG emissions associated with this 
carbon is being reported under other provisions of this part, in either 
gas, liquid, or solid forms (metric tons carbon).
    (8) Annual quantity of methanol intentionally produced as a desired 
product, if applicable, (metric tons) for each process unit.
    (9) Annual net quantity of steam consumed by the unit, (metric 
tons). Include steam purchased or produced outside of the hydrogen 
production unit. If the hydrogen production unit is a net producer of 
steam, enter the annual net quantity of steam consumed by the unit as a 
negative value.
    (10) An indication (yes or no) if best available monitoring methods 
were used, in accordance with Sec.  98.164(c), to determine fuel flow 
for each stationary combustion unit directly associated with hydrogen 
production (e.g., reforming furnace and hydrogen production process 
unit heater). If yes, report:
    (i) The beginning date of using best available monitoring methods, 
in accordance with Sec.  98.164(c), to determine fuel flow for each 
stationary combustion unit directly associated with hydrogen production 
(e.g., reforming furnace and hydrogen production process unit heater).
    (ii) The anticipated or actual end date of using best available 
monitoring methods, as applicable, in accordance with Sec.  98.164(c), 
to determine fuel flow for each stationary combustion unit directly 
associated with hydrogen production (e.g., reforming furnace and 
hydrogen production process unit heater).

0
47. Amend Sec.  98.167 by:
0
a. Revising paragraphs (a) and (b);
0
b. Removing and reserving paragraph (c); and
0
c. Revising paragraphs (d) and (e) introductory text.
    The revisions read as follows:


Sec.  98.167  Records that must be retained.

* * * * *
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec.  98.37, and, if the CEMS measures 
emissions from a common stack for multiple hydrogen production units or 
emissions from a common stack for hydrogen production unit(s) and other 
source(s), records used to estimate the decimal fraction of the total 
annual CO2 emissions from the CEMS monitoring location 
attributable to each hydrogen production unit.
    (b) You must retain records of all analyses and calculations 
conducted to determine the values reported in Sec.  98.166(b).
* * * * *
    (d) The owner or operator must document the procedures used to 
ensure the accuracy of the estimates of fuel and feedstock usage in 
Sec.  98.163(b), including, but not limited to, calibration of weighing 
equipment, fuel and feedstock flow meters, and other measurement 
devices. The estimated accuracy of measurements made with these devices 
must also be recorded, and the technical basis for these estimates must 
be provided.
    (e) The applicable verification software records as identified in 
this paragraph (e). You must keep a record of the file generated by the 
verification software specified in Sec.  98.5(b) for the applicable 
data specified in paragraphs (e)(1) through (12) of this section. 
Retention of this file satisfies the recordkeeping requirement for the 
data in paragraphs (e)(1) through (12) of this section for each 
hydrogen production unit.
* * * * *

[[Page 31928]]

Subpart Q--Iron and Steel Production

0
48. Amend Sec.  98.173 by revising equation Q-5 in paragraph (b)(1)(v) 
to read as follows:


Sec.  98.173  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) * * *
    (v) * * *
    [GRAPHIC] [TIFF OMITTED] TR25AP24.040
    
* * * * *

0
49. Amend Sec.  98.174 by:
0
a. Revising paragraph (b)(2) introductory text;
0
b. Redesignating paragraph (b)(2)(vi) as paragraph (b)(2)(vii); and
0
c. Adding new paragraph (b)(2)(vi).
    The revision and addition read as follows:


Sec.  98.174   Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (2) Except as provided in paragraph (b)(4) of this section, 
determine the carbon content of each process input and output annually 
for use in the applicable equations in Sec.  98.173(b)(1) based on 
analyses provided by the supplier, analyses provided by material 
recyclers who manage process outputs for sale or use by other 
industries, or by the average carbon content determined by collecting 
and analyzing at least three samples each year using the standard 
methods specified in paragraphs (b)(2)(i) through (vii) of this section 
as applicable.
* * * * *
    (vi) ASTM E415-17, Standard Test Method for Analysis of Carbon and 
Low-Alloy Steel by Spark Atomic Emission Spectrometry (incorporated by 
reference, see Sec.  98.7) as applicable for steel.
* * * * *

0
50. Amend Sec.  98.176 by revising paragraphs (e)(2) and adding 
paragraph (g) to read as follows:


Sec.  98.176   Data reporting requirements.

* * * * *
    (e) * * *
    (2) Whether the carbon content was determined from information from 
the supplier, material recycler, or by laboratory analysis, and if by 
laboratory analysis, the method used in Sec.  98.174(b)(2).
* * * * *
    (g) For each unit, the type of unit, the annual production 
capacity, and annual operating hours.
* * * * *

Subpart S--Lime Manufacturing

0
51. Amend Sec.  98.193 by revising equation S-4 in paragraph (b)(2)(iv) 
to read as follows:


Sec.  98.193   Calculating GHG emissions.

* * * * *
    (b) * * *
    (2) * * *
    (iv) * * *
    [GRAPHIC] [TIFF OMITTED] TR25AP24.041
    
* * * * *

0
52. Amend Sec.  98.196 by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) through (14);
0
c. Revising paragraphs (b) introductory text and (b)(17); and
0
d. Adding paragraphs (b)(22) and (23).
    The revisions and additions read as follows:


Sec.  98.196   Data reporting requirements.

* * * * *
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec.  98.36 and the information listed in paragraphs (a)(1) through 
(14) of this section.
* * * * *
    (9) Annual arithmetic average of calcium oxide content for each 
type of lime product produced (metric tons CaO/metric ton lime).
    (10) Annual arithmetic average of magnesium oxide content for each 
type of lime product produced (metric tons MgO/metric ton lime).
    (11) Annual arithmetic average of calcium oxide content for each 
type of calcined lime byproduct/waste sold (metric tons CaO/metric ton 
lime).
    (12) Annual arithmetic average of magnesium oxide content for each 
type of calcined lime byproduct/waste sold (metric tons MgO/metric ton 
lime).
    (13) Annual arithmetic average of calcium oxide content for each 
type of calcined lime byproduct/waste not sold (metric tons CaO/metric 
ton lime).
    (14) Annual arithmetic average of magnesium oxide content for each 
type of calcined lime byproduct/waste not sold (metric tons MgO/metric 
ton lime)
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in paragraphs (b)(1) through 
(23) of this section.
* * * * *
    (17) Indicate whether CO2 was captured and used on-site 
(e.g., for use in a purification process, the manufacture of another 
product). If CO2 was captured and used on-site, provide the 
information in paragraphs (b)(17)(i) and (ii) of this section.
    (i) The annual amount of CO2 captured for use in all on-
site processes.
    (ii) The method used to determine the amount of CO2 
captured.
* * * * *
    (22) Annual average results of chemical composition analysis of all 
lime byproducts or wastes not sold.

[[Page 31929]]

    (23) Annual quantity (tons) of all lime byproducts or wastes not 
sold.

Subpart U--Miscellaneous Uses of Carbonate

0
53. Amend Sec.  98.210 by revising paragraph (b) to read as follows:


Sec.  98.210   Definition of the source category.

* * * * *
    (b) This source category does not include equipment that uses 
carbonates or carbonate containing minerals that are consumed in the 
production of cement, glass, ferroalloys, iron and steel, lead, lime, 
phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium 
hydroxide, zinc, or ceramics.
* * * * *

Subpart X-Petrochemical Production

0
54. Amend Sec.  98.243 by revising paragraphs (b)(3) and (d)(5) to read 
as follows:


Sec.  98.243   Calculating GHG emissions.

* * * * *
    (b) * * *
    (3) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec.  
98.253(b).
* * * * *
    (d) * * *
    (5) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec.  
98.253(b).

0
55. Amend Sec.  98.244 by revising paragraph (b)(4)(iii) to read as 
follows:


Sec.  98.244   Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (4) * * *
    (iii) ASTM D2505-88 (Reapproved 2004)e1 (incorporated by reference, 
see Sec.  98.7).
* * * * *

0
56. Amend Sec.  98.246 by revising paragraphs (a) introductory text, 
(a)(2), (5), (13) and (15), (b)(7) and (8), and (c) to read as follows:


Sec.  98.246   Data reporting requirements.

* * * * *
    (a) If you use the mass balance methodology in Sec.  98.243(c), you 
must report the information specified in paragraphs (a)(1) through (15) 
of this section for each type of petrochemical produced, reported by 
process unit.
* * * * *
    (2) The type of petrochemical produced.
* * * * *
    (5) Annual quantity of each type of petrochemical produced from 
each process unit (metric tons). If you are electing to consider the 
petrochemical process unit to be the entire integrated ethylene 
dichloride/vinyl chloride monomer process, the portion of the total 
amount of ethylene dichloride (EDC) produced that is used in vinyl 
chloride monomer (VCM) production may be a measured quantity or an 
estimate that is based on process knowledge and best available data. 
The portion of the total amount of EDC produced that is not utilized in 
VCM production must be measured in accordance with Sec.  98.244(b)(2) 
or (3). Sum the amount of EDC used in the production of VCM plus the 
amount of separate EDC product to report as the total quantity of EDC 
petrochemical from an integrated EDC/VCM petrochemical process unit.
* * * * *
    (13) Name and annual quantity (in metric tons) of each product 
included in equations X-1, X-2, and X-3 to Sec.  98.243. If you are 
electing to consider the petrochemical process unit to be the entire 
integrated ethylene dichloride/vinyl chloride monomer process, the 
reported quantity of EDC product should include only that which was not 
used in the VCM process.
* * * * *
    (15) For each gaseous feedstock or product for which the volume was 
used in equation X-1 to Sec.  98.243, report the annual average 
molecular weight of the measurements or determinations, conducted 
according to Sec.  98.243(c)(3) or (4). Report the annual average 
molecular weight in units of kg per kg mole.
    (b) * * *
    (7) Information listed in Sec.  98.256(e) for each flare that burns 
process off-gas. Additionally, provide estimates based on engineering 
judgment of the fractions of the total CO2, CH4 
and N2O emissions that are attributable to combustion of 
off-gas from the petrochemical process unit(s) served by the flare.
    (8) Annual quantity of each type of petrochemical produced from 
each process unit (metric tons).
* * * * *
    (c) If you comply with the combustion methodology specified in 
Sec.  98.243(d), you must report under this subpart the information 
listed in paragraphs (c)(1) through (6) of this section.
    (1) The ethylene process unit ID or other appropriate descriptor.
    (2) For each stationary combustion unit that burns ethylene process 
off-gas (or group of stationary sources with a common pipe), except 
flares, the relevant information listed in Sec.  98.36 for the 
applicable Tier methodology. For each stationary combustion unit or 
group of units (as applicable) that burns ethylene process off-gas, 
provide an estimate based on engineering judgment of the fraction of 
the total emissions that is attributable to combustion of off-gas from 
the ethylene process unit.
    (3) Information listed in Sec.  98.256(e) for each flare that burns 
ethylene process off-gas. Additionally, provide estimates based on 
engineering judgment of the fractions of the total CO2, 
CH4 and N2O emissions that are attributable to 
combustion of off-gas from the ethylene process unit(s) served by the 
flare.
    (4) Name and annual quantity of each carbon-containing feedstock 
(metric tons).
    (5) Annual quantity of ethylene produced from each process unit 
(metric tons).
    (6) Name and annual quantity (in metric tons) of each product 
produced in each process unit.

Subpart Y--Petroleum Refineries

0
57. Amend Sec.  98.250 by revising paragraph (c) to read as follows:


Sec.  98.250   Definition of source category.

* * * * *
    (c) This source category consists of the following sources at 
petroleum refineries: Catalytic cracking units; fluid coking units; 
delayed coking units; catalytic reforming units; asphalt blowing 
operations; blowdown systems; storage tanks; process equipment 
components (compressors, pumps, valves, pressure relief devices, 
flanges, and connectors) in gas service; marine vessel, barge, tanker 
truck, and similar loading operations; flares; and sulfur recovery 
plants.


Sec.  98.252   [Amended]

0
58. Amend Sec.  98.252 by removing and reserving paragraphs (e) and 
(i).

0
59. Amend Sec.  98.253 by:
0
a. Revising the introductory text of paragraphs (b) and (c);
0
b. Revising and republishing paragraphs (c)(4) and (5);
0
c. Revising paragraph (e) introductory text;
0
d. Removing and reserving paragraph (g); and
0
e. Revising and republishing paragraphs (i)(2) and (5).
    The revisions read as follows:


Sec.  98.253   Calculating GHG emissions.

* * * * *
    (b) For flares, calculate GHG emissions according to the 
requirements in paragraphs (b)(1) through (3) of this section. All gas 
discharged through the flare stack must be included in the flare

[[Page 31930]]

GHG emissions calculations with the exception of the following, which 
may be excluded as applicable: gas used for the flare pilots, and if 
using the calculation method in paragraph (b)(1)(iii) of this section, 
the gas released during start-up, shutdown, or malfunction events of 
500,000 scf/day or less.
* * * * *
    (c) For catalytic cracking units and traditional fluid coking 
units, calculate the GHG emissions from coke burn-off using the 
applicable methods described in paragraphs (c)(1) through (5) of this 
section.
* * * * *
    (4) Calculate CH4 emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source 
test of the unit, or equation Y-9 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.042

Where:

CH4 = Annual methane emissions from coke burn-off (metric 
tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off 
calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this 
section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from table C-1 to subpart C of this part (kg 
CO2/MMBtu).
EmF2 = Default CH4 emission factor for 
``PetroleumProducts'' from table C-2 to subpart C of this part (kg 
CH4/MMBtu).

    (5) Calculate N2O emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source 
test of the unit, or equation Y-10 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.043

Where:

N2O = Annual nitrous oxide emissions from coke burn-off 
(mt N2O/year).
CO2 = Emission rate of CO2 from coke burn-off 
calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this 
section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from table C-1 to subpart C of this part (kg 
CO2/MMBtu).
EmF3 = Default N2O emission factor for 
``PetroleumProducts'' from table C-2 to subpart C of this part (kg 
N2O/MMBtu).

* * * * *
    (e) For catalytic reforming units, calculate the CO2 
emissions from coke burn-off using the applicable methods described in 
paragraphs (e)(1) through (3) of this section and calculate the 
CH4 and N2O emissions using the methods described 
in paragraphs (c)(4) and (5) of this section, respectively.
* * * * *
    (i) * * *
    (2) Determine the typical mass of water in the delayed coking unit 
vessel at the end of the cooling cycle prior to venting to the 
atmosphere using equation Y-18b to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.044

Where:

Mwater = Mass of water in the delayed coking unit vessel 
at the end of the cooling cycle just prior to atmospheric venting or 
draining (metric tons/cycle).
rwater = Density of water at average temperature of the 
delayed coking unit vessel at the end of the cooling cycle just 
prior to atmospheric venting (metric tons per cubic feet; mt/ft\3\). 
Use the default value of 0.0270 mt/ft\3\.
Hwater = Typical distance from the bottom of the coking 
unit vessel to the top of the water level at the end of the cooling 
cycle just prior to atmospheric venting or draining (feet) from 
company records or engineering estimates.
fcoke = Fraction of the coke-filled bed that is covered 
by water at the end of the cooling cycle just prior to atmospheric 
venting or draining. Use 1 if the water fully covers coke-filled 
portion of the coke drum.
Mcoke = Typical dry mass of coke in the delayed coking 
unit vessel at the end of the coking cycle (metric tons/cycle) as 
determined in paragraph (i)(1) of this section.
rparticle = Particle density of coke (metric tons per 
cubic feet; mt/ft\3\). Use the default value of 0.0382 mt/ft\3\.
D = Diameter of delayed coking unit vessel (feet).

* * * * *
    (5) Calculate the CH4 emissions from decoking operations 
at each delayed coking unit using equation Y-18f to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.045

Where:

CH4 = Annual methane emissions from the delayed coking 
unit decoking operations (metric ton/year).
Msteam = Mass of steam generated and released per 
decoking cycle (metric tons/cycle) as determined in paragraph (i)(4) 
of this section.
EmFDCU = Methane emission factor for delayed coking unit 
(kilograms CH4 per metric ton of steam; kg 
CH4/mt steam) from unit-specific measurement data. If you 
do not have unit-specific measurement data, use the default value of 
7.9 kg CH4/metric ton steam.
N = Cumulative number of decoking cycles (or coke-cutting cycles) 
for all delayed coking unit vessels associated with the delayed 
coking unit during the year.
0.001 = Conversion factor (metric ton/kg).

* * * * *

0
60. Amend Sec.  98.254 by:
0
a. Revising the introductory text of paragraphs (d) and (e); and

[[Page 31931]]

0
b. Removing and reserving paragraphs (h) and (i).
    The revisions read as follows:


Sec.  98.254   Monitoring and QA/QC requirements.

* * * * *
    (d) Except as provided in paragraph (g) of this section, determine 
gas composition and, if required, average molecular weight of the gas 
using any of the following methods. Alternatively, the results of 
chromatographic or direct mass spectrometer analysis of the gas may be 
used, provided that the gas chromatograph or mass spectrometer is 
operated, maintained, and calibrated according to the manufacturer's 
instructions; and the methods used for operation, maintenance, and 
calibration of the gas chromatograph or mass spectrometer are 
documented in the written Monitoring Plan for the unit under Sec.  
98.3(g)(5).
* * * * *
    (e) Determine flare gas higher heating value using any of the 
following methods. Alternatively, the results of chromatographic 
analysis of the gas may be used, provided that the gas chromatograph is 
operated, maintained, and calibrated according to the manufacturer's 
instructions; and the methods used for operation, maintenance, and 
calibration of the gas chromatograph are documented in the written 
Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *


Sec.  98.255   [Amended]

0
61. Amend Sec.  98.255 by removing and reserving paragraph (d).

0
62. Amend Sec.  98.256 by:
0
a. Removing and reserving paragraphs (b) and (i);
0
b. Adding paragraph (j)(2); and
0
c. Revising paragraph (k)(6).
    The addition and revision read as follows:


Sec.  98.256   Data reporting requirements.

* * * * *
    (j) * * *
    (2) Maximum rated throughput of the unit, in metric tons asphalt/
stream day.
* * * * *
    (k) * * *
    (6) The basis for the typical dry mass of coke in the delayed 
coking unit vessel at the end of the coking cycle (mass measurements 
from company records or calculated using equation Y-18a to Sec.  
98.253). If you use mass measurements from company records to determine 
the typical dry mass of coke in the delayed coking unit vessel at the 
end of the coking cycle, you must also report:
    (i) Internal height of delayed coking unit vessel (feet) for each 
delayed coking unit.
    (ii) Typical distance from the top of the delayed coking unit 
vessel to the top of the coke bed (i.e. , coke drum outage) at the end 
of the coking cycle (feet) from company records or engineering 
estimates for each delayed coking unit.
* * * * *

0
63. Amend Sec.  98.257 by:
0
a. Revising paragraphs (b)(16) through (19);
0
b. Removing and reserving paragraphs (b)(27) through (31);
0
c. Revising paragraphs (b)(45), (46), and (53); and
0
d. Removing and reserving paragraphs (b)(54) through (56).
    The revisions read as follows:


Sec.  98.257  Records that must be retained.

* * * * *
    (b) * * *
    (16) Value of unit-specific CH4 emission factor, 
including the units of measure, for each catalytic cracking unit, 
traditional fluid coking unit, and catalytic reforming unit 
(calculation method in Sec.  98.253(c)(4)).
    (17) Annual activity data (e.g. , input or product rate), including 
the units of measure, in units of measure consistent with the emission 
factor, for each catalytic cracking unit, traditional fluid coking 
unit, and catalytic reforming unit (calculation method in Sec.  
98.253(c)(4)).
    (18) Value of unit-specific N2O emission factor, 
including the units of measure, for each catalytic cracking unit, 
traditional fluid coking unit, and catalytic reforming unit 
(calculation method in Sec.  98.253(c)(5)).
    (19) Annual activity data (e.g. , input or product rate), including 
the units of measure, in units of measure consistent with the emission 
factor, for each catalytic cracking unit, traditional fluid coking 
unit, and catalytic reforming unit (calculation method in Sec.  
98.253(c)(5)).
* * * * *
    (45) Mass of water in the delayed coking unit vessel at the end of 
the cooling cycle prior to atmospheric venting or draining (metric ton/
cycle) (equations Y-18b and Y-18e to Sec.  98.253) for each delayed 
coking unit.
    (46) Typical distance from the bottom of the coking unit vessel to 
the top of the water level at the end of the cooling cycle just prior 
to atmospheric venting or draining (feet) from company records or 
engineering estimates (equation Y-18b to Sec.  98.253) for each delayed 
coking unit.
* * * * *
    (53) Fraction of the coke-filled bed that is covered by water at 
the end of the cooling cycle just prior to atmospheric venting or 
draining (equation Y-18b to Sec.  98.253) for each delayed coking unit.
* * * * *

Subpart AA--Pulp and Paper Manufacturing

0
64. Revise and republish Sec.  98.273 to read as follows:


Sec.  98.273  Calculating GHG emissions.

    (a) For each chemical recovery furnace located at a kraft or soda 
facility, you must determine CO2, biogenic CO2, 
CH4, and N2O emissions using the procedures in 
paragraphs (a)(1) through (4) of this section. CH4 and N2O emissions 
must be calculated as the sum of emissions from combustion of fuels and 
combustion of biomass in spent liquor solids.
    (1) Calculate CO2 emissions from fuel combustion using 
direct measurement of fuels consumed and default emissions factors 
according to the Tier 1 methodology for stationary combustion sources 
in Sec.  98.33(a)(1). Tiers 2 or 3 from Sec.  98.33(a)(2) or (3) may be 
used to calculate CO2 emissions if the respective monitoring 
and QA/QC requirements described in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from fuel 
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons 
of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec.  98.33(c).
    (3) Calculate biogenic CO2 emissions and emissions of 
CH4 and N2O from biomass using measured 
quantities of spent liquor solids fired, site-specific HHV, and default 
emissions factors, according to equation AA-1 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.046

Where:

CO2, CH4, or N2O, from Biomass = 
Biogenic CO2 emissions or emissions of CH4 or 
N2O from spent liquor solids combustion (metric tons per 
year).

[[Page 31932]]

Solids = Mass of spent liquor solids combusted (short tons per year) 
determined according to Sec.  98.274(b).
HHV = Annual high heat value of the spent liquor solids (mmBtu per 
kilogram) determined according to Sec.  98.274(b).
EF = Default emission factor for CO2, CH4, or 
N2O, from table AA-1 to this subpart (kg CO2, 
CH4, or N2O per mmBtu).
0.90718 = Conversion factor from short tons to metric tons.

    (4) Calculate biogenic CO2 emissions from combustion of 
biomass (other than spent liquor solids) with other fuels according to 
the applicable methodology for stationary combustion sources in Sec.  
98.33(e).
    (b) For each chemical recovery combustion unit located at a sulfite 
or stand-alone semichemical facility, you must determine 
CO2, CH4, and N2O emissions using the 
procedures in paragraphs (b)(1) through (5) of this section:
    (1) Calculate CO2 emissions from fuel combustion using 
direct measurement of fuels consumed and default emissions factors 
according to the Tier 1 Calculation Methodology for stationary 
combustion sources in Sec.  98.33(a)(1). Tiers 2 or 3 from Sec.  
98.33(a)(2) or (3) may be used to calculate CO2 emissions if 
the respective monitoring and QA/QC requirements described in Sec.  
98.34 are met.
    (2) Calculate CH4 and N2O emissions from fuel 
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons 
of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec.  98.33(c).
    (3) Calculate biogenic CO2 emissions using measured 
quantities of spent liquor solids fired and the carbon content of the 
spent liquor solids, according to equation AA-2 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.047

Where:

Biogenic CO2 = Annual CO2 mass emissions for 
spent liquor solids combustion (metric tons per year).
Solids = Mass of the spent liquor solids combusted (short tons per 
year) determined according to Sec.  98.274(b).
CC = Annual carbon content of the spent liquor solids, determined 
according to Sec.  98.274(b) (percent by weight, expressed as a 
decimal fraction, e.g. , 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.90718 = Conversion from short tons to metric tons.

    (4) Calculate biogenic CO2 emissions from combustion of 
biomass (other than spent liquor solids) with other fuels according to 
the applicable methodology for stationary combustion sources in Sec.  
98.33(e).
    (c) For each pulp mill lime kiln located at a kraft or soda 
facility, you must determine CO2, CH4, and 
N2O emissions using the procedures in paragraphs (c)(1) 
through (4) of this section:
    (1) Calculate CO2 emissions from fuel combustion using 
direct measurement of fuels consumed and default HHV and default 
emissions factors, according to the Tier 1 Calculation Methodology for 
stationary combustion sources in Sec.  98.33(a)(1). Tiers 2 or 3 from 
Sec.  98.33(a)(2) or (3) may be used to calculate CO2 
emissions if the respective monitoring and QA/QC requirements described 
in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from fuel 
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons 
of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec.  98.33(c); use the default HHV 
listed in table C-1 to subpart C of this part and the default 
CH4 and N2O emissions factors listed in table AA-
2 to this subpart.
    (3) Biogenic CO2 emissions from conversion of 
CaCO3 to CaO are included in the biogenic CO2 
estimates calculated for the chemical recovery furnace in paragraph 
(a)(3) of this section.
    (4) Calculate biogenic CO2 emissions from combustion of 
biomass with other fuels according to the applicable methodology for 
stationary combustion sources in Sec.  98.33(e).
    (d) For makeup chemical use, you must calculate CO2 
emissions by using direct or indirect measurement of the quantity of 
chemicals added and ratios of the molecular weights of CO2 
and the makeup chemicals, according to equation AA-3 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.048

Where:

CO2 = CO2 mass emissions from makeup chemicals 
(kilograms/yr).
M (CaCO3) = Make-up quantity of CaCO3 used for 
the reporting year (metric tons per year).
M (NaCO3) = Make-up quantity of 
Na2CO3 used for the reporting year (metric 
tons per year).
44 = Molecular weight of CO2.
100 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.


0
65. Amend Sec.  98.276 by revising paragraph (a) to read as follows:


Sec.  98.276  Data reporting requirements.

* * * * *
    (a) Annual emissions of CO2, biogenic CO2, 
CH4, and N2O (metric tons per year).
* * * * *

0
66. Amend Sec.  98.277 by revising paragraph (d) to read as follows:


Sec.  98.277   Records that must be retained.

* * * * *
    (d) Annual quantity of spent liquor solids combusted in each 
chemical recovery furnace and chemical recovery combustion unit, and 
the basis for determining the annual quantity of the spent liquor 
solids combusted (whether based on T650 om-05 Solids Content of Black 
Liquor, TAPPI (incorporated by reference, see Sec.  98.7) or an online 
measurement system). If an online measurement system is used, you must 
retain records of the calculations used to determine the annual 
quantity of spent liquor solids combusted from the continuous 
measurements.
* * * * *

Subpart BB--Silicon Carbide Production

0
67. Amend Sec.  98.286 by revising the introductory text and adding 
paragraph (c) to read as follows:


Sec.  98.286  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified

[[Page 31933]]

in paragraph (a) or (b) of this section, and paragraph (c) of this 
section, as applicable for each silicon carbide production facility.
* * * * *
    (c) If methane abatement technology is used at the silicon carbide 
production facility, you must report the information in paragraphs 
(c)(1) through (3) of this section. Upon reporting this information 
once in an annual report, you are not required to report this 
information again unless the information changes during a reporting 
year, in which case, the reporter must include any updates in the 
annual report for the reporting year in which the change occurred.
    (1) Type of methane abatement technology used on each silicon 
carbide process unit or production furnace, and date of installation 
for each.
    (2) Methane destruction efficiency for each methane abatement 
technology (percent destruction). You must either use the 
manufacturer's specified destruction efficiency or the destruction 
efficiency determined via a performance test. If you report the 
destruction efficiency determined via a performance test, you must also 
report the test method that was used during the performance test.
    (3) Percentage of annual operating hours that methane abatement 
technology was in use for all silicon carbide process units or 
production furnaces combined.

0
68. Amend Sec.  98.287 by revising the introductory text and adding 
paragraph (d) to read as follows:


Sec.  98.287  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section for each silicon carbide production facility.
* * * * *
    (d) Records of all information reported as required under Sec.  
98.286(c).

0
69. Revise and republish subpart DD consisting of Sec. Sec.  98.300 
through 98.308 to read as follows:

Subpart DD--Electrical Transmission and Distribution Equipment Use

Sec.
98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC requirements.
98.305 Procedures for estimating missing data.
98.306 Data reporting requirements.
98.307 Records that must be retained.
98.308 Definitions.


Sec.  98.300   Definition of the source category.

    (a) The electrical transmission and distribution equipment use 
source category consists of all electric transmission and distribution 
equipment and servicing inventory insulated with or containing 
fluorinated GHGs, including but not limited to sulfur hexafluoride 
(SF6) and perfluorocarbons (PFCs), used within an electric 
power system. Electric transmission and distribution equipment and 
servicing inventory includes, but is not limited to:
    (1) Gas-insulated substations.
    (2) Circuit breakers.
    (3) Switchgear, including closed-pressure and hermetically sealed-
pressure switchgear and gas-insulated lines containing fluorinated 
GHGs, including but not limited to SF6 and PFCs.
    (4) Gas containers such as pressurized cylinders.
    (5) Gas carts.
    (6) Electric power transformers.
    (7) Other containers of fluorinated GHG, including but not limited 
to SF6 and PFCs.
    (b) [Reserved]


Sec.  98.301  Reporting threshold.

    (a) You must report GHG emissions under this subpart if you are an 
electric power system as defined in Sec.  98.308 and your facility 
meets the requirements of Sec.  98.2(a)(1). To calculate total annual 
GHG emissions for comparison to the 25,000 metric ton CO2e 
per year emission threshold in table A-3 to subpart A to this part, you 
must calculate emissions of each fluorinated GHG that is a component of 
a reportable insulating gas and then sum the emissions of each 
fluorinated GHG resulting from the use of electrical transmission and 
distribution equipment for threshold applicability purposes using 
equation DD-1 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.049

Where:

E = Annual emissions for threshold applicability purposes (metric 
tons CO2e).
NCEPS,j = the total nameplate capacity of equipment 
containing reportable insulating gas j (excluding hermetically 
sealed-pressure equipment) located within the facility plus the 
total nameplate capacity of equipment containing reportable 
insulting gas j (excluding hermetically sealed-pressure equipment) 
that is not located within the facility but is under common 
ownership or control (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j in the gas insulated equipment included 
in the total nameplate capacity NCEPS,j, expressed as a 
decimal fraction. If fluorinated GHG i is not part of a gas mixture, 
use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
EF = Emission factor for electrical transmission and distribution 
equipment (lbs emitted/lbs nameplate capacity). For all gases, use 
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and 
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.

    (b) A facility other than an electric power system that is subject 
to this part because of emissions from any other source category listed 
in table A-3 or A-4 to subpart A of this part is not required to report 
emissions under subpart DD of this part unless the total estimated 
emissions of fluorinated GHGs that are components of reportable 
insulating gases, as calculated in equation DD-2 to this section, 
equals or exceeds 25,000 tons CO2e.
[GRAPHIC] [TIFF OMITTED] TR25AP24.050

Where:

E = Annual emissions for threshold applicability purposes (metric 
tons CO2e).
NCother,j = For a facility other than an electric power 
system, the total nameplate capacity of equipment containing 
reportable insulating gas j (excluding hermetically sealed-pressure 
equipment) located within the facility (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j in the gas insulated equipment included 
in

[[Page 31934]]

the total nameplate capacity NCother,j, expressed as a 
decimal fraction. If fluorinated GHG i is not part of a gas mixture, 
use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
EF = Emission factor for electrical transmission and distribution 
equipment (lbs emitted/lbs nameplate capacity). For all gases, use 
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and 
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.


Sec.  98.302   GHGs to report.

    You must report emissions of each fluorinated GHG, including but 
not limited to SF6 and PFCs, from your facility (including 
emissions from fugitive equipment leaks, installation, servicing, 
equipment decommissioning and disposal, and from storage cylinders) 
resulting from the transmission and distribution servicing inventory 
and equipment listed in Sec.  98.300(a), except you are not required to 
report emissions of fluorinated GHGs that are components of insulating 
gases whose weighted average GWPs, as calculated in equation DD-3 to 
this section, are less than or equal to one. For acquisitions of 
equipment containing or insulated with fluorinated GHGs, you must 
report emissions from the equipment after the title to the equipment is 
transferred to the electric power transmission or distribution entity.
[GRAPHIC] [TIFF OMITTED] TR25AP24.051

Where:

GWPj = Weighted average GWP of insulating gas j.
GHGi,w = The weight fraction of GHG i in insulating gas 
j, expressed as a decimal. fraction. If GHG i is not part of a gas 
mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
i = GHG contained in the electrical transmission and distribution 
equipment.


Sec.  98.303   Calculating GHG emissions.

    (a) Calculating GHG emissions. Calculate the annual emissions of 
each fluorinated GHG that is a component of any reportable insulating 
gas using the mass-balance approach in equation DD-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.052

Where:

User Emissionsi = Emissions of fluorinated GHG i from the 
facility (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j if reportable insulating gas j is a gas 
mixture, expressed as a decimal fraction. If fluorinated GHG i is 
not part of a gas mixture, use a value of 1.0.
Decrease in Inventory of Reportable Insulating Gas j = (Pounds of 
reportable insulating gas j stored in containers, but not in 
energized equipment, at the beginning of the year)-(Pounds of 
reportable insulating gas j stored in containers, but not in 
energized equipment, at the end of the year). Reportable insulating 
gas inside equipment that is not energized is considered to be 
``stored in containers.''
Acquisitions of Reportable Insulating gas j = (Pounds of reportable 
insulating gas j purchased or otherwise acquired from chemical 
producers, chemical distributors, or other entities in bulk) + 
(Pounds of reportable insulating gas j purchased or otherwise 
acquired from equipment manufacturers, equipment distributors, or 
other entities with or inside equipment, including hermetically 
sealed-pressure switchgear, while the equipment was not in use) + 
(Pounds of each SF6 insulating gas j returned to facility 
after off-site recycling) + (Pounds of reportable insulating gas j 
acquired inside equipment, except hermetically sealed-pressure 
switchgear, that was transferred while the equipment was in use, 
e.g., through acquisition of all or part of another electric power 
system).
Disbursements of Reportable Insulating gas j = (Pounds of reportable 
insulating gas j returned to suppliers) + (Pounds of reportable 
insulating gas j sent off site for recycling) + (Pounds of 
reportable insulating gas j sent off-site for destruction) + (Pounds 
of reportable insulating gas j that was sold or transferred to other 
entities in bulk) + (Pounds of reportable insulating gas j contained 
in equipment, including hermetically sealed-pressure switchgear, 
that was sold or transferred to other entities while the equipment 
was not in use) + (Pounds of reportable insulating gas j inside 
equipment, except hermetically sealed-pressure switchgear, that was 
transferred while the equipment was in use, e.g., through sale of 
all or part of the electric power system to another electric power 
system).
Net Increase in Total Nameplate Capacity of Equipment Operated 
containing reportable insulating gas j = (The Nameplate Capacity of 
new equipment, as defined at Sec.  98.308, containing reportable 
insulating gas j in pounds)-(Nameplate Capacity of retiring 
equipment, as defined at Sec.  98.308, containing reportable 
insulating gas j in pounds). (Note that Nameplate Capacity refers to 
the full and proper charge of equipment rather than to the actual 
charge, which may reflect leakage).

    (b) Nameplate capacity adjustments. Users of closed-pressure 
electrical equipment with a voltage capacity greater than 38 kV may 
measure and adjust the nameplate capacity value specified by the 
equipment manufacturer on the nameplate attached to that equipment, or 
within the equipment manufacturer's official product specifications, by 
following the requirements in paragraphs (b)(1) through (10) of this 
section. Users of other electrical equipment are not permitted to 
adjust the nameplate capacity value of the other equipment.
    (1) If you elect to measure the nameplate capacity value(s) of one 
or more pieces of electrical equipment with a voltage capacity greater 
than 38 kV, you must measure the nameplate capacity values of all the 
electrical

[[Page 31935]]

equipment in your facility that has a voltage capacity greater than 38 
kV and that is installed or retired in that reporting year and in 
subsequent reporting years.
    (2) You must adopt the measured nameplate capacity value for any 
piece of equipment for which the absolute value of the difference 
between the measured nameplate capacity value and the nameplate 
capacity value most recently specified by the manufacturer equals or 
exceeds two percent of the nameplate capacity value most recently 
specified by the manufacturer.
    (3) You may adopt the measured nameplate capacity value for 
equipment for which the absolute value of the difference between the 
measured nameplate capacity value and the nameplate capacity value most 
recently specified by the manufacturer is less than two percent of the 
nameplate capacity value most recently specified by the manufacturer, 
but if you elect to adopt the measured nameplate capacity for that 
equipment, then you must adopt the measured nameplate capacity value 
for all of the equipment for which the difference between the measured 
nameplate capacity value and the nameplate capacity value most recently 
specified by the manufacturer is less than two percent of the nameplate 
capacity value most recently specified by the manufacturer. This 
applies in the reporting year in which you first adopt the measured 
nameplate capacity for the equipment and in subsequent reporting years.
    (4) Users of electrical equipment measuring the nameplate capacity 
of any new electrical equipment must:
    (i) Record the amount of insulating gas in the equipment at the 
time the equipment was acquired (pounds), either per information 
provided by the manufacturer, or by transferring insulating gas from 
the equipment to a gas container and measuring the amount of insulating 
gas transferred. The equipment user is responsible for ensuring the gas 
is accounted for consistent with the methodologies specified in 
paragraphs (b)(4)(ii) through (iii) and (b)(5) of this section. If no 
insulating gas was in the device when it was acquired, record this 
value as zero.
    (ii) If insulating gas is added to the equipment subsequent to the 
acquisition of the equipment to energize it the first time, transfer 
the insulating gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications. 
Follow the manufacturer-specified procedure to ensure that the measured 
temperature accurately reflects the temperature of the insulating gas, 
e.g., by measuring the insulating gas pressure and vessel temperature 
after allowing appropriate time for the temperature of the transferred 
gas to equilibrate with the vessel temperature. Measure and calculate 
the total amount of reportable insulating gas added to the device using 
one of the methods specified in paragraphs (b)(4)(ii)(A) and (B) of 
this section.
    (A) To determine the amount of reportable insulating gas 
transferred to the electrical equipment, weigh the gas container being 
used to fill the device prior to, and after, the addition of the 
reportable insulating gas to the electrical equipment, and subtract the 
second value (after-transfer gas container weight) from the first value 
(prior-to-transfer gas container weight). Account for any gas contained 
in hoses before and after the transfer.
    (B) Connect a mass flow meter between the electrical equipment and 
a gas cart. Transfer gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications. 
During gas transfer, you must keep the mass flow rate within the range 
specified by the mass flow meter manufacturer to assure an accurate and 
precise mass flow meter reading. Close the connection to the GIE from 
the mass flow meter hose and ensure that the gas trapped in the filling 
hose returns through the mass flow meter. Calculate the amount of gas 
transferred from the mass reading on the mass flow meter.
    (iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain 
the measured nameplate capacity for the new equipment.
    (5) Electrical equipment users measuring the nameplate capacity of 
any retiring electrical equipment must:
    (i) Measure and record the initial system pressure and vessel 
temperature prior to removing any insulating gas.
    (ii) Compare the initial system pressure and temperature to the 
equipment manufacturer's temperature/pressure curve for that equipment 
and insulating gas.
    (iii) If the temperature-compensated initial system pressure of the 
electrical equipment does not match the temperature-compensated design 
operating pressure specified by the equipment manufacturer, you may 
either:
    (A) Add or remove insulating gas to/from the electrical equipment 
until the manufacturer-specified value is reached, or
    (B) If the temperature-compensated initial system pressure of the 
electrical equipment is no higher than the temperature-compensated 
design operating pressure specified by the manufacturer and no lower 
than five pounds per square inch (5 psi) less than the temperature-
compensated design operating pressure specified by the manufacturer, 
use equation DD-5 to this section to calculate the nameplate capacity 
based on the mass recorded under paragraph (b)(5)(vi) of this section.
    (iv) Weigh the gas container being used to receive the gas and 
record this value.
    (v) Recover insulating gas from the electrical equipment until five 
minutes after the pressure in the electrical equipment reaches a 
pressure of at most five pounds per square inch absolute (5 psia).
    (vi) Record the amount of insulating gas recovered (pounds) by 
weighing the gas container that received the gas and subtracting the 
weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section 
from this value. Account for any gas contained in hoses before and 
after the transfer. The amount of gas recovered shall be the measured 
nameplate capacity for the electrical equipment unless the final 
temperature-compensated pressure of the electrical equipment exceeds 
0.068 psia (3.5 Torr) or the electrical equipment user is calculating 
the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this 
section, in which cases the measured nameplate capacity shall be the 
result of equation DD-5 to this section.
    (vii) If you are calculating the nameplate capacity pursuant to 
paragraph (b)(5)(iii)(B) of this section, use equation DD-5 to this 
section to do so.
[GRAPHIC] [TIFF OMITTED] TR25AP24.053


[[Page 31936]]


Where:

NCC = Nameplate capacity of the equipment measured and 
calculated by the equipment user (pounds).
Pi = Initial temperature-compensated pressure of the 
equipment, based on the temperature-pressure curve for the 
insulating gas (psia).
Pf = Final temperature-compensated pressure of the 
equipment, based on the temperature-pressure curve for the 
insulating gas (psia). This may be equated to zero if the final 
temperature-compensated pressure of the equipment is equal to or 
lower than 0.068 psia (3.5 Torr).
PNC = Temperature-compensated pressure of the equipment 
at the manufacturer-specified filling density of the equipment 
(i.e., at the full and proper charge, psia).
MR = Mass of insulating gas recovered from the equipment, 
measured in paragraph (b)(5)(vi) of this section (pounds).

    (viii) Record the final system pressure and vessel temperature.
    (6) Instead of measuring the nameplate capacity of electrical 
equipment when it is retired, users may measure the nameplate capacity 
of electrical equipment during maintenance activities that require 
opening the gas compartment, but they must follow the procedures set 
forth in paragraph (b)(5) of this section.
    (7) If the electrical equipment will remain energized, and the 
electrical equipment user is adopting the user-measured nameplate 
capacity, the electrical equipment user must affix a revised nameplate 
capacity label, showing the revised nameplate value and the year the 
nameplate capacity adjustment process was performed, to the device by 
the end of the calendar year in which the process was completed. The 
manufacturer's previous nameplate capacity label must remain visible 
after the revised nameplate capacity label is affixed to the device.
    (8) For each piece of electrical equipment whose nameplate capacity 
was adjusted during the reporting year, the revised nameplate capacity 
value must be used in all provisions wherein the nameplate capacity is 
required to be recorded, reported, or used in a calculation in this 
subpart unless otherwise specified herein.
    (9) The nameplate capacity of a piece of electrical equipment may 
only be adjusted more than once if the physical capacity of the device 
has changed (e.g., replacement of bushings) after the initial 
adjustment was performed, in which case the equipment user must adjust 
the nameplate capacity pursuant to the provisions of this paragraph 
(b).
    (10) Measuring devices used to measure the nameplate capacity of 
electrical equipment under this paragraph (b) must meet the following 
accuracy and precision requirements:
    (i) Flow meters must be certified by the manufacturer to be 
accurate and precise to within one percent of the largest value that 
the flow meter can, according to the manufacturer's specifications, 
accurately record.
    (ii) Pressure gauges must be certified by the manufacturer to be 
accurate and precise to within 0.5% of the largest value that the gauge 
can, according to the manufacturer's specifications, accurately record.
    (iii) Temperature gauges must be certified by the manufacturer to 
be accurate and precise to within +/-1.0 [deg]F.
    (iv) Scales must be certified by the manufacturer to be accurate 
and precise to within one percent of the true weight.


Sec.  98.304  Monitoring and QA/QC requirements.

    (a) [Reserved]
    (b) You must adhere to the following QA/QC methods for reviewing 
the completeness and accuracy of reporting:
    (1) Review inputs to equation DD-4 to Sec.  98.303 to ensure inputs 
and outputs to the company's system are included.
    (2) Do not enter negative inputs and confirm that negative 
emissions are not calculated. However, the Decrease in fluorinated GHG 
Inventory and the Net Increase in Total Nameplate Capacity may be 
calculated as negative numbers.
    (3) Ensure that beginning-of-year inventory matches end-of-year 
inventory from the previous year.
    (4) Ensure that in addition to fluorinated GHG purchased from bulk 
gas distributors, fluorinated GHG purchased from Original Equipment 
Manufacturers (OEM) and fluorinated GHG returned to the facility from 
off-site recycling are also accounted for among the total additions.
    (c) Ensure the following QA/QC methods are employed throughout the 
year:
    (1) Ensure that cylinders returned to the gas supplier are 
consistently weighed on a scale that is certified to be accurate and 
precise to within 2 pounds of true weight and is periodically 
recalibrated per the manufacturer's specifications. Either measure 
residual gas (the amount of gas remaining in returned cylinders) or 
have the gas supplier measure it. If the gas supplier weighs the 
residual gas, obtain from the gas supplier a detailed monthly 
accounting, within 2 pounds, of residual gas amounts in the 
cylinders returned to the gas supplier.
    (2) Ensure that cylinders weighed for the beginning and end of year 
inventory measurements are weighed on a scale that is certified to be 
accurate and precise to within 2 pounds of true weight and is 
periodically recalibrated per the manufacturer's specifications. All 
scales used to measure quantities that are to be reported under Sec.  
98.306 must be calibrated using calibration procedures specified by the 
scale manufacturer. Calibration must be performed prior to the first 
reporting year. After the initial calibration, recalibration must be 
performed at the minimum frequency specified by the manufacturer.
    (3) Ensure all substations have provided information to the manager 
compiling the emissions report (if it is not already handled through an 
electronic inventory system).
    (d) GHG Monitoring Plans, as described in Sec.  98.3(g)(5), must be 
completed by April 1, 2011.


Sec.  98.305  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Replace missing data, if needed, 
based on data from equipment with a similar nameplate capacity for 
fluorinated GHGs, and from similar equipment repair, replacement, and 
maintenance operations.


Sec.  98.306  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each electric 
power system, by chemical:
    (a) Nameplate capacity of equipment (pounds) containing each 
insulating gas:
    (1) Existing at the beginning of the year (excluding hermetically 
sealed-pressure switchgear).
    (2) New hermetically sealed-pressure switchgear during the year.
    (3) New equipment other than hermetically sealed-pressure 
switchgear during the year.
    (4) Retired hermetically sealed-pressure switchgear during the 
year.
    (5) Retired equipment other than hermetically sealed-pressure 
switchgear during the year.
    (b) Transmission miles (length of lines carrying voltages above 35 
kilovolts).
    (c) Distribution miles (length of lines carrying voltages at or 
below 35 kilovolts).
    (d) Pounds of each reportable insulating gas stored in containers, 
but not in energized equipment, at the beginning of the year.
    (e) Pounds of each reportable insulating gas stored in containers, 
but not in energized equipment, at the end of the year.

[[Page 31937]]

    (f) Pounds of each reportable insulating gas purchased or otherwise 
acquired in bulk from chemical producers, chemical distributors, or 
other entities.
    (g) Pounds of each reportable insulating gas purchased or otherwise 
acquired from equipment manufacturers, equipment distributors, or other 
entities with or inside equipment, including hermetically sealed-
pressure switchgear, while the equipment was not in use.
    (h) Pounds of each reportable insulating gas returned to facility 
after off-site recycling.
    (i) Pounds of each reportable insulating gas acquired inside 
equipment, except hermetically sealed-pressure switchgear, that was 
transferred while the equipment was in use, e.g., through acquisition 
of all or part of another electric power system.
    (j) Pounds of each reportable insulating gas returned to suppliers.
    (k) Pounds of each reportable insulating gas that was sold or 
transferred to other entities in bulk.
    (l) Pounds of each reportable insulating gas sent off-site for 
recycling.
    (m) Pounds of each reportable insulating gas sent off-site for 
destruction.
    (n) Pounds of each reportable insulating gas contained in 
equipment, including hermetically sealed-pressure switchgear, that was 
sold or transferred to other entities while the equipment was not in 
use.
    (o) Pounds of each reportable insulating gas disbursed inside 
equipment, except hermetically sealed-pressure switchgear, that was 
transferred while the equipment was in use, e.g., through sale of all 
or part of the electric power system to another electric power system.
    (p) State(s) or territory in which the facility lies.
    (q) The number of reportable-insulating-gas-containing pieces of 
equipment in each of the following equipment categories:
    (1) New hermetically sealed-pressure switchgear during the year.
    (2) New equipment other than hermetically sealed-pressure 
switchgear during the year.
    (3) Retired hermetically sealed-pressure switchgear during the 
year.
    (4) Retired equipment other than hermetically sealed-pressure 
switchgear during the year.
    (r) The total of the nameplate capacity values most recently 
assigned by the electrical equipment manufacturer(s) to each of the 
following groups of equipment:
    (1) All new equipment whose nameplate capacity values were measured 
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
    (2) All retiring equipment whose nameplate capacity values were 
measured by the user under this subpart and for which the user adopted 
the user-measured nameplate capacity value during the year.
    (s) The total of the nameplate capacity values measured by the 
electrical equipment user for each of the following groups of 
equipment:
    (1) All new equipment whose nameplate capacity values were measured 
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
    (2) All retiring equipment whose nameplate capacity values were 
measured by the user under this subpart and for which the user adopted 
the user-measured nameplate capacity value during the year.
    (t) For each reportable insulating gas reported in paragraphs (a), 
(d) through (o), and (q) of this section, an ID number or other 
appropriate descriptor that is unique to that reportable insulating 
gas.
    (u) For each ID number or descriptor reported in paragraph (t) of 
this section for each unique insulating gas, the name (as required in 
Sec.  98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas 
in the insulating gas.


Sec.  98.307   Records that must be retained.

    (a) In addition to the information required by Sec.  98.3(g), you 
must retain records of the information reported and listed in Sec.  
98.306.
    (b) For each piece of electrical equipment whose nameplate capacity 
is measured by the equipment user, retain records of the following:
    (1) Equipment manufacturer name.
    (2) Year equipment was manufactured. If the date year the equipment 
was manufactured cannot be determined, report a best estimate of the 
year of manufacture and record how the estimated year was determined.
    (3) Manufacturer serial number. For any piece of equipment whose 
serial number is unknown (e.g., the serial number does not exist or is 
not visible), another unique identifier must be recorded as the 
manufacturer serial number. The electrical equipment user must retain 
documentation that allows for each electrical equipment to be readily 
identifiable.
    (4) Equipment type (i.e., closed-pressure vs. hermetically sealed-
pressure).
    (5) Equipment voltage capacity (in kilovolts).
    (6) The name and GWP of each insulating gas used.
    (7) Nameplate capacity value (pounds), as specified by the 
equipment manufacturer. The value must reflect the latest value 
specified by the manufacturer during the reporting year.
    (8) Nameplate capacity value (pounds) measured by the equipment 
user.
    (9) The date the nameplate capacity measurement process was 
completed.
    (10) The measurements and calculations used to calculate the value 
in paragraph (b)(8) of this section.
    (11) The temperature-pressure curve and/or other information used 
to derive the initial and final temperature-adjusted pressures of the 
equipment.
    (12) Whether or not the nameplate capacity value in paragraph 
(b)(8) of this section has been adopted for the piece of electrical 
equipment.


Sec.  98.308   Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Facility, with respect to an electric power system, means the 
electric power system as set out in this definition. An electric power 
system is comprised of all electric transmission and distribution 
equipment insulated with or containing fluorinated GHGs that is linked 
through electric power transmission or distribution lines and functions 
as an integrated unit, that is owned, serviced, or maintained by a 
single electric power transmission or distribution entity (or multiple 
entities with a common owner), and that is located between:
    (1) The point(s) at which electric energy is obtained from an 
electricity generating unit or a different electric power transmission 
or distribution entity that does not have a common owner; and
    (2) The point(s) at which any customer or another electric power 
transmission or distribution entity that does not have a common owner 
receives the electric energy. The facility also includes servicing 
inventory for such equipment that contains fluorinated GHGs.
    Electric power transmission or distribution entity means any entity 
that transmits, distributes, or supplies electricity to a consumer or 
other user, including any company, electric cooperative, public 
electric supply corporation, a similar Federal department (including 
the Bureau of Reclamation or the Corps of Engineers), a municipally 
owned electric department offering service to the

[[Page 31938]]

public, an electric public utility district, or a jointly owned 
electric supply project.
    Energized, for the purposes of this subpart, means connected 
through busbars or cables to an electrical power system or fully-
charged, ready for service, and being prepared for connection to the 
electrical power system. Energized equipment does not include spare gas 
insulated equipment (including hermetically-sealed pressure switchgear) 
in storage that has been acquired by the facility, and is intended for 
use by the facility, but that is not being used or prepared for 
connection to the electrical power system.
    Insulating gas, for the purposes of this subpart, means any 
fluorinated GHG or fluorinated GHG mixture, including but not limited 
to SF6 and PFCs, that is used as an insulating and/or arc-
quenching gas in electrical equipment.
    New equipment, for the purposes of this subpart, means either any 
gas insulated equipment, including hermetically-sealed pressure 
switchgear, that is not energized at the beginning of the reporting 
year but is energized at the end of the reporting year, or any gas 
insulated equipment other than hermetically-sealed pressure switchgear 
that has been transferred while in use, meaning it has been added to 
the facility's inventory without being taken out of active service 
(e.g., when the equipment is sold to or acquired by the facility while 
remaining in place and continuing operation).
    Operator, for the purposes of this subpart, means any person who 
operates or supervises a facility, excluding a person whose sole 
responsibility is to ensure reliability, balance load or otherwise 
address electricity flow.
    Reportable insulating gas, for purposes of this subpart, means an 
insulating gas whose weighted average GWP, as calculated in equation 
DD-3 to Sec.  98.302, is greater than one. A fluorinated GHG that makes 
up either part or all of a reportable insulating gas is considered to 
be a component of the reportable insulating gas.
    Retired equipment, for the purposes of this subpart, means either 
any gas insulated equipment including hermetically-sealed pressure 
switchgear, that is energized at the beginning of the reporting year 
but is not energized at the end of the reporting year, or any gas 
insulated equipment other than hermetically-sealed pressure switchgear 
that has been transferred while in use, meaning it has been removed 
from the facility's inventory without being taken out of active service 
(e.g., when the equipment is acquired by a new facility while remaining 
in place and continuing operation).

Subpart FF--Underground Coal Mines

0
70. Amend Sec.  98.323 by revising parameter ``MCFi'' of equation FF-3 
in paragraph (b) introductory text to read as follows:


Sec.  98.323  Calculating GHG emissions.

* * * * *
    (b) * * *

MCFi = Moisture correction factor for the measurement 
period, volumetric basis.
    = 1 when Vi and Ci are measured on a dry 
basis or if both are measured on a wet basis.
    = 1-(fH2O)i when Vi is measured on a wet 
basis and Ci is measured on a dry basis.
    = 1/[1-(fH2O)i] when Vi is measured on a 
dry basis and Ci is measured on a wet basis.
* * * * *

0
71. Amend Sec.  98.326 by revising paragraph (t) to read as follows:


Sec.  98.326  Data reporting requirements.

* * * * *
    (t) Mine Safety and Health Administration (MSHA) identification 
number for this coal mine.

Subpart GG--Zinc Production

0
72. Amend Sec.  98.333 by revising paragraph (b)(1) introductory text 
to read as follows:


Sec.  98.333  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) For each Waelz kiln or electrothermic furnace at your facility 
used for zinc production, you must determine the mass of carbon in each 
carbon-containing material, other than fuel, that is fed, charged, or 
otherwise introduced into each Waelz kiln and electrothermic furnace at 
your facility for each year and calculate annual CO2 process 
emissions from each affected unit at your facility using equation GG-1 
to this section. For electrothermic furnaces, carbon containing input 
materials include carbon electrodes and carbonaceous reducing agents. 
For Waelz kilns, carbon containing input materials include carbonaceous 
reducing agents. If you document that a specific material contributes 
less than 1 percent of the total carbon into the process, you do not 
have to include the material in your calculation using equation R-1 to 
Sec.  98.183.
* * * * *

0
73. Amend Sec.  98.336 by adding paragraphs (a)(6) and (b)(6) to read 
as follows:


Sec.  98.336   Data reporting requirements.

* * * * *
    (a) * * *
    (6) Total amount of electric arc furnace dust annually consumed by 
all Waelz kilns at the facility (tons).
    (b) * * *
    (6) Total amount of electric arc furnace dust annually consumed by 
all Waelz kilns at the facility (tons).
* * * * *

Subpart HH--Municipal Solid Waste Landfills

0
74. Amend Sec.  98.343 by revising paragraphs (a)(2) and (c)(3) to read 
as follows:


Sec.  98.343  Calculating GHG emissions.

    (a) * * *
    (2) For years when material-specific waste quantity data are 
available, apply equation HH-1 to this section for each waste quantity 
type and sum the CH4 generation rates for all waste types to 
calculate the total modeled CH4 generation rate for the 
landfill. Use the appropriate parameter values for k, DOC, MCF, 
DOCF, and F shown in table HH-1 to this subpart. The annual 
quantity of each type of waste disposed must be calculated as the sum 
of the daily quantities of waste (of that type) disposed. You may use 
the uncharacterized MSW parameters for a portion of your waste 
materials when using the material-specific modeling approach for mixed 
waste streams that cannot be designated to a specific material type. 
For years when waste composition data are not available, use the bulk 
waste parameter values for k and DOC in table HH-1 to this subpart for 
the total quantity of waste disposed in those years.
* * * * *
    (c) * * *
    (3) For landfills with landfill gas collection systems, calculate 
CH4 emissions using the methodologies specified in 
paragraphs (c)(3)(i) and (ii) of this section.
    (i) Calculate CH4 emissions from the modeled 
CH4 generation and measured CH4 recovery using 
equation HH-6 to this section.

[[Page 31939]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.054

Where:

Emissions = Methane emissions from the landfill in the reporting 
year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year 
from equation HH-1 to this section or the quantity of recovered 
CH4 from equation HH-4 to this section, whichever is 
greater (metric tons CH4).
N = Number of landfill gas measurement locations (associated with a 
destruction device or gas sent off-site). If a single monitoring 
location is used to monitor volumetric flow and CH4 
concentration of the recovered gas sent to one or multiple 
destruction devices, then N = 1.
Rn = Quantity of recovered CH4 from equation 
HH-4 to this section for the nth measurement location (metric tons 
CH4).
OX = Oxidation fraction. Use the appropriate oxidation fraction 
default value from table HH-4 to this subpart.
DEn = Destruction efficiency (lesser of manufacturer's 
specified destruction efficiency and 0.99) for the nth measurement 
location. If the gas is transported off-site for destruction, use DE 
= 1. If the volumetric flow and CH4 concentration of the 
recovered gas is measured at a single location providing landfill 
gas to multiple destruction devices (including some gas destroyed 
on-site and some gas sent off-site for destruction), calculate 
DEn as the arithmetic average of the DE values determined 
for each destruction device associated with that measurement 
location.
fDest,n = Fraction of hours the destruction device 
associated with the nth measurement location was operating during 
active gas flow calculated as the annual operating hours for the 
destruction device divided by the annual hours flow was sent to the 
destruction device. The annual operating hours for the destruction 
device should include only those periods when flow was sent to the 
destruction device and the destruction device was operating at its 
intended temperature or other parameter indicative of effective 
operation. For flares, times when there is no flame present must be 
excluded from the annual operating hours for the destruction device. 
If the gas is transported off-site for destruction, use 
fDest,n = 1. If the volumetric flow and CH4 
concentration of the recovered gas is measured at a single location 
providing landfill gas to multiple destruction devices (including 
some gas destroyed on-site and some gas sent off-site for 
destruction), calculate fDest,n as the arithmetic average 
of the fDest values determined for each destruction 
device associated with that measurement location.

    (ii) Calculate CH4 generation and CH4 
emissions using measured CH4 recovery and estimated gas 
collection efficiency and equations HH-7 and HH-8 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.055

Where:

MG = Methane generation, adjusted for oxidation, from the landfill 
in the reporting year (metric tons CH4).
Emissions = Methane emissions from the landfill in the reporting 
year (metric tons CH4).
C = Number of landfill gas collection systems operated at the 
landfill.
X = Number of landfill gas measurement locations associated with 
landfill gas collection system ``c''.
N = Number of landfill gas measurement locations (associated with a 
destruction device or gas sent off-site). If a single monitoring 
location is used to monitor volumetric flow and CH4 
concentration of the recovered gas sent to one or multiple 
destruction devices, then N = 1. Note that N = 
S(c=1)C[S(x=1)X[1]].
Rx,c = Quantity of recovered CH4 from equation 
HH-4 to this section for the xth measurement location for landfill 
gas collection system ``c'' (metric tons CH4).
Rn = Quantity of recovered CH4 from equation 
HH-4 to this section for the nth measurement location (metric tons 
CH4).
CE = Collection efficiency estimated at landfill, taking into 
account system coverage, operation, measurement practices, and cover 
system materials from table HH-3 to this subpart. If area by soil 
cover type information is not available, use applicable default 
value for CE4 in table HH-3 to this subpart for all areas under 
active influence of the collection system.
fRec,c = Fraction of hours the landfill gas collection 
system ``c'' was operating normally (annual operating hours/8760 
hours per year or annual operating hours/8784 hours per year for a 
leap year). Do not include periods of shutdown or poor operation, 
such as times when pressure, temperature, or other parameters 
indicative of operation are outside of normal variances, in the 
annual operating hours.
OX = Oxidation fraction. Use appropriate oxidation fraction default 
value from table HH-4 to this subpart.
DEn = Destruction efficiency, (lesser of manufacturer's 
specified destruction efficiency and 0.99) for the nth measurement 
location. If the gas is transported off-site for destruction, use DE 
= 1. If the volumetric flow and CH4 concentration of the 
recovered gas is measured at a single location providing landfill 
gas to multiple destruction devices (including some gas destroyed 
on-site and some gas sent off-site for destruction), calculate 
DEn as the arithmetic average of the DE values determined 
for each destruction device associated with that measurement 
location.
fDest,n = Fraction of hours the destruction device 
associated with the nth measurement location was operating during 
active gas flow calculated as the annual operating hours for the 
destruction device divided by the annual hours flow was sent to the 
destruction device. The annual operating hours for the destruction 
device should include only those periods when flow was sent to the 
destruction device and the destruction device was operating at its 
intended temperature or other parameter indicative of effective 
operation. For flares, times when there is no flame present must be 
excluded from the annual operating hours for the destruction device. 
If the gas is transported off-site for destruction, use 
fDest,n = 1. If the volumetric flow and CH4 
concentration of the recovered gas is measured at a single location 
providing landfill gas to multiple destruction devices (including 
some gas destroyed on-site and some gas sent off-site for 
destruction), calculate fDest,n as the arithmetic average 
of the fDest values determined for each destruction 
device

[[Page 31940]]

associated with that measurement location.

0
75. Amend Sec.  98.346 by:
0
a. Redesignating paragraphs (h) and (i) as paragraphs (i) and (j), 
respectively.
0
b. Adding new paragraph (h); and
0
c. Revising newly redesignated paragraphs (j)(5) through (7).
    The addition and revisions read as follows:


Sec.  98.346   Data reporting requirements.

* * * * *
    (h) An indication of the applicability of part 60 or part 62 of 
this chapter requirements to the landfill (part 60, subparts WWW and 
XXX of this chapter, approved state plan implementing part 60, subparts 
Cc or Cf of this chapter, Federal plan as implemented at part 62, 
subparts GGG or OOO of this chapter, or not subject to part 60 or part 
62 of this chapter municipal solid waste landfill rules), and if the 
landfill is subject to a part 60 or part 62 of this chapter municipal 
solid waste landfill rule, an indication of whether the landfill gas 
collection system is required under part 60 or part 62 of this chapter.
* * * * *
    (j) * * *
    (5) The number of gas collection systems at the landfill facility.
    (6) For each gas collection system at the facility report:
    (i) A unique name or ID number for the gas collection system.
    (ii) A description of the gas collection system (manufacturer, 
capacity, and number of wells).
    (iii) The annual hours the gas collection system was operating 
normally. Do not include periods of shut down or poor operation, such 
as times when pressure, temperature, or other parameters indicative of 
operation are outside of normal variances, in the annual operating 
hours.
    (iv) The number of measurement locations associated with the gas 
collection system.
    (v) For each measurement location associated with the gas 
collection system, report:
    (A) A unique name or ID number for the measurement location.
    (B) Annual quantity of recovered CH4 (metric tons 
CH4) calculated using equation HH-4 to Sec.  98.343.
    (C) An indication of whether destruction occurs at the landfill 
facility, off-site, or both for the measurement location.
    (D) If destruction occurs at the landfill facility for the 
measurement location (in full or in part), also report the number of 
destruction devices associated with the measurement location that are 
located at the landfill facility and the information in paragraphs 
(j)(6)(v)(D)(1) through (6) of this section for each destruction device 
located at the landfill facility.
    (1) A unique name or ID number for the destruction device.
    (2) The type of destruction device (flare, a landfill gas to energy 
project (i.e., engine or turbine), off-site, or other (specify)).
    (3) The destruction efficiency (decimal).
    (4) The total annual hours where active gas flow was sent to the 
destruction device.
    (5) The annual operating hours where active gas flow was sent to 
the destruction device and the destruction device was operating at its 
intended temperature or other parameter indicative of effective 
operation. For flares, times when there is no flame present must be 
excluded from the annual operating hours for the destruction device.
    (6) The estimated fraction of the recovered CH4 reported for the 
measurement location directed to the destruction device based on best 
available data or engineering judgement (decimal, must total to 1 for 
each measurement location).
    (7) The following information about the landfill.
    (i) The surface area (square meters) and estimated waste depth 
(meters) for each area specified in table HH-3 to this subpart.
    (ii) The estimated gas collection system efficiency for the 
landfill.
    (iii) An indication of whether passive vents and/or passive flares 
(vents or flares that are not considered part of the gas collection 
system as defined in Sec.  98.6) are present at the landfill.
* * * * *

0
76. Revise table HH-1 to subpart HH to read as follows:

              Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation Factors and Methods
----------------------------------------------------------------------------------------------------------------
                Factor                      Default value                             Units
----------------------------------------------------------------------------------------------------------------
DOC and k values--Bulk waste option:
    DOC (bulk waste) for disposal      0.20...................  Weight fraction, wet basis.
     years prior to 2010.
    DOC (bulk waste) for disposal      0.17...................  Weight fraction, wet basis.
     years 2010 and later.
    k (precipitation plus              0.02...................  yr-\1\.
     recirculated leachate \a\ <20
     inches/year) for disposal years
     prior to 2010.
    k (precipitation plus              0.033..................  yr-\1\.
     recirculated leachate \a\ <20
     inches/year) for disposal years
     2010 and later.
    k (precipitation plus              0.038..................  yr-\1\.
     recirculated leachate \a\ 20-40
     inches/year) for disposal years
     prior to 2010.
    k (precipitation plus              0.067..................  yr-\1\.
     recirculated leachate \a\ 20-40
     inches/year) for disposal years
     2010 and later.
    k (precipitation plus              0.057..................  yr-\1\.
     recirculated leachate \a\ >40
     inches/year) for disposal years
     prior to 2010.
    k (precipitation plus              0.098..................  yr-\1\.
     recirculated leachate \a\ >40
     inches/year) for disposal years
     2010 and later.
DOC and k values--Modified bulk MSW
 option:
    DOC (bulk MSW, excluding inerts    0.31...................  Weight fraction, wet basis.
     and C&D waste) for disposal
     years prior to 2010.
    DOC (bulk MSW, excluding inerts    0.27...................  Weight fraction, wet basis.
     and C&D waste) for disposal
     years 2010 and later.
    DOC (inerts, e.g., glass,          0.00...................  Weight fraction, wet basis.
     plastics, metal, concrete).
    DOC (C&D waste)..................  0.08...................  Weight fraction, wet basis.
    k (bulk MSW, excluding inerts and  0.02 to 0.057 \b\......  yr-\1\.
     C&D waste) for disposal years
     prior to 2010.
    k (bulk MSW, excluding inerts and  0.033 to 0.098 \b\.....  yr-\1\.
     C&D waste) for disposal years
     2010 and later.

[[Page 31941]]

 
    k (inerts, e.g., glass, plastics,  0.00...................  yr-\1\.
     metal, concrete).
    k (C&D waste)....................  0.02 to 0.04 \b\.......  yr-\1\.
DOC and k values--Waste composition
 option:
    DOC (food waste).................  0.15...................  Weight fraction, wet basis.
    DOC (garden).....................  0.2....................  Weight fraction, wet basis.
    DOC (paper)......................  0.4....................  Weight fraction, wet basis.
    DOC (wood and straw).............  0.43...................  Weight fraction, wet basis.
    DOC (textiles)...................  0.24...................  Weight fraction, wet basis.
    DOC (diapers)....................  0.24...................  Weight fraction, wet basis.
    DOC (sewage sludge)..............  0.05...................  Weight fraction, wet basis.
    DOC (inerts, e.g., glass,          0.00...................  Weight fraction, wet basis.
     plastics, metal, cement).
    DOC (Uncharacterized MSW.........  0.32...................  Weight fraction, wet basis.
    k (food waste)...................  0.06 to 0.185 \c\......  yr-\1\.
    k (garden).......................  0.05 to 0.10 \c\.......  yr-\1\.
    k (paper)........................  0.04 to 0.06 \c\.......  yr-\1\.
    k (wood and straw)...............  0.02 to 0.03 \c\.......  yr-\1\.
    k (textiles).....................  0.04 to 0.06 \c\.......  yr-\1\.
    k (diapers)......................  0.05 to 0.10 \c\.......  yr-\1\.
    k (sewage sludge)................  0.06 to 0.185 \c\......  yr-\1\.
    k (inerts, e.g., glass, plastics,  0.00...................  yr-\1\.
     metal, concrete).
    k (uncharacterized MSW)..........  0.033 to 0.098 \b\.....  yr-\1\.
Other parameters--All MSW landfills:
    MCF..............................  1......................
    DOCF.............................  0.5....................
    F................................  0.5....................
    OX...............................  See table HH-4 to this
                                        subpart.
    DE...............................  0.99...................
----------------------------------------------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or
  engineering estimates divided by the area of the portion of the landfill containing waste with appropriate
  unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of
  0.098 rather than calculating the recirculated leachate rate.
\b\ Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the
  greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of
  the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive).
  Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than
  calculating the recirculated leachate rate.
\c\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate
  plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed
  the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate
  recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate
  or recirculated leachate rate.


0
77. Revise table HH-3 to subpart HH to read as follows:

      Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection
                              Efficiencies
------------------------------------------------------------------------
                                                         Landfill gas
          Description                  Term ID            collection
                                                          efficiency
------------------------------------------------------------------------
A1: Area with no waste in-place  Not applicable; do not use this area in
                                             the calculation.
                                ----------------------------------------
A2: Area without active gas      CE2................  0%.
 collection, regardless of
 cover type.
A3: Area with daily soil cover   CE3................  50%.
 and active gas collection.
A4: Area with an intermediate    CE4................  65%.
 soil cover, or a final soil
 cover not meeting the criteria
 for A5 below, and active gas
 collection.
A5: Area with a final soil       CE5................  85%.
 cover of 3 feet or thicker of
 clay or final cover (as
 approved by the relevant
 agency) and/or geomembrane
 cover system and active gas
 collection.
                                ----------------------------------------
Area weighted average              CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 +
 collection efficiency for             A5*CE5)/(A2 + A3 + A4 + A5).
 landfills.
------------------------------------------------------------------------


0
78. Revise footnote ``b'' to table HH--4 to subpart HH to read as 
follows:

[[Page 31942]]



     Table HH-4 to Subpart HH of Part 98--Landfill Methane Oxidation
                                Fractions
------------------------------------------------------------------------
                                                       Use this landfill
                                                       methane oxidation
               Under these conditions:                     fraction:
 
------------------------------------------------------------------------
 
                              * * * * * * *
------------------------------------------------------------------------
 * * * * * * *
\b\ Methane flux rate (in grams per square meter per day; g/m\2\/d) is
  the mass flow rate of methane per unit area at the bottom of the
  surface soil prior to any oxidation and is calculated as follows:

    For equation HH-5 to Sec.  98.343, or for equation TT-6 to Sec.  
98.463,

MF = K x GCH4/SArea

    For equation HH-6 to Sec.  98.343,
    [GRAPHIC] [TIFF OMITTED] TR25AP24.056
    
    For equation HH-7 to Sec.  98.343,
    [GRAPHIC] [TIFF OMITTED] TR25AP24.057
    
    For equation HH-8 to Sec.  98.343,
    [GRAPHIC] [TIFF OMITTED] TR25AP24.058
    
Where:

MF = Methane flux rate from the landfill in the reporting year 
(grams per square meter per day, g/m\2\/d).
K = unit conversion factor = 10⁶/365 (g/metric ton per 
days/year) or 10⁶/366 for a leap year.
SArea = The surface area of the landfill containing waste at the 
beginning of the reporting year (square meters, m\2\).
GCH4 = Modeled methane generation rate in reporting year 
from equation HH-1 to Sec.  98.343 or equation TT-1 to Sec.  98.463, 
as applicable, except for application with equation HH-6 to Sec.  
98.343 (metric tons CH4). For application with equation 
HH-6 to Sec.  98.343, the greater of the modeled methane generation 
rate in reporting year from equation HH-1 to Sec.  98.343 or 
equation TT-1 to Sec.  98.463, as applicable, and the quantity of 
recovered CH4 from equation HH-4 to Sec.  98.343 (metric 
tons CH4).
CE = Collection efficiency estimated at landfill, taking into 
account system coverage, operation, measurement practices, and cover 
system materials from table HH-3 to this subpart. If area by soil 
cover type information is not available, use applicable default 
value for CE4 in table HH-3 to this subpart for all areas under 
active influence of the collection system.
C = Number of landfill gas collection systems operated at the 
landfill.
X = Number of landfill gas measurement locations associated with 
landfill gas collection system ``c''.
N = Number of landfill gas measurement locations (associated with a 
destruction device or gas sent off-site). If a single monitoring 
location is used to monitor volumetric flow and CH4 
concentration of the recovered gas sent to one or multiple 
destruction devices, then N = 1. Note that N = 
[Sigma]c=1C[[Sigma]x=1X[1]].
Rx,c = Quantity of recovered CH4 from equation 
HH-4 to Sec.  98.343 for the x\th\ measurement location for landfill 
gas collection system ``c'' (metric tons CH4).
Rn = Quantity of recovered CH4 from equation 
HH-4 to Sec.  98.343 for the n\th\ measurement location (metric tons 
CH4).
fRec,c = Fraction of hours the landfill gas collection 
system ``c'' was operating normally (annual operating hours/8,760 
hours per year or annual operating hours/8,784 hours per year for a 
leap year). Do not include periods of shutdown or poor operation, 
such as times when pressure, temperature, or other parameters 
indicative of operation are outside of normal variances, in the 
annual operating hours.

Subpart OO--Suppliers of Industrial Greenhouse Gases

0
79. Amend Sec.  98.416 by revising paragraphs (c) introductory text, 
(c)(6) and (7), (d) introductory text, and (d)(4), and adding paragraph 
(k) to read as follows:


Sec.  98.416  Data reporting requirements.

* * * * *
    (c) Each bulk importer of fluorinated GHGs, fluorinated heat 
transfer fluids (HTFs), or nitrous oxide shall submit an annual report 
that summarizes its imports at the corporate level, except importers 
may exclude shipments including less than twenty-five kilograms of 
fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if 
the importer also excludes transshipments from reporting of exports 
under paragraph (d) of this section; and heels that meet the conditions 
set forth at Sec.  98.417(e) if the importer also excludes heels from 
any reporting of exports under paragraph (d) of this section. The 
report shall contain

[[Page 31943]]

the following information for each import:
* * * * *
    (6) Harmonized tariff system (HTS) code of the fluorinated GHGs, 
fluorinated HTFs, or nitrous oxide shipped.
    (7) Customs entry number and importer number for each shipment.
* * * * *
    (d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or 
nitrous oxide shall submit an annual report that summarizes its exports 
at the corporate level, except reporters may exclude shipments 
including less than twenty-five kilograms of fluorinated GHGs, 
fluorinated HTFs, or nitrous oxide; transshipments if the exporter also 
excludes transshipments from reporting of imports under paragraph (c) 
of this section; and heels if the exporter also excludes heels from any 
reporting of imports under paragraph (c) of this section. The report 
shall contain the following information for each export:
* * * * *
    (4) Harmonized tariff system (HTS) code of the fluorinated GHGs, 
fluorinated HTFs, or nitrous oxide shipped.
* * * * *
    (k) For nitrous oxide, saturated perfluorocarbons, sulfur 
hexafluoride, and fluorinated heat transfer fluids as defined at Sec.  
98.6, report the end use(s) for which each GHG or fluorinated HTF is 
transferred and the aggregated annual quantity of that GHG or 
fluorinated HTF in metric tons that is transferred to that end use 
application, if known.

Subpart PP--Suppliers of Carbon Dioxide

0
80. Amend Sec.  98.420 by adding paragraph (a)(4) to read as follows:


Sec.  98.420   Definition of the source category.

    (a) * * *
    (4) Facilities with process units, including but not limited to 
direct air capture (DAC), that capture a CO2 stream from 
ambient air for purposes of supplying CO2 for commercial 
applications or that capture and maintain custody of a CO2 
stream in order to sequester or otherwise inject it underground.
* * * * *

0
81. Amend Sec.  98.422 by adding paragraph (e) to read as follows:


Sec.  98.422  GHGs to report.

* * * * *
    (e) Mass of CO2 captured from DAC process units.
    (1) Mass of CO2 captured from ambient air.
    (2) Mass of CO2 captured from any on-site heat and/or 
electricity generation, where applicable.

0
82. Amend Sec.  98.423 by revising paragraphs (a)(3)(i) introductory 
text and (a)(3)(ii) introductory text to read as follows:


Sec.  98.423  Calculating CO2 supply.

    (a) * * *
    (3) * * *
    (i) For facilities with production process units, DAC process 
units, or production wells that capture or extract a CO2 
stream and either measure it after segregation or do not segregate the 
flow, calculate the total CO2 supplied in accordance with 
equation PP-3a to paragraph (a)(3)(i) of this section.
* * * * *
    (ii) For facilities with production process units or DAC process 
units that capture a CO2 stream and measure it ahead of 
segregation, calculate the total CO2 supplied in accordance 
with equation PP-3b to paragraph (a)(3)(ii) of this section.
* * * * *

0
83. Amend Sec.  98.426 by:
0
a. Redesignating paragraphs (f)(12) and (13) as paragraphs (f)(13) and 
(14), respectively;
0
b. Adding new paragraph (f)(12);
0
c. Revising paragraph (h); and
0
d. Adding paragraph (i).
    The additions and revision read as follows:


Sec.  98.426  Data reporting requirements.

* * * * *
    (f) * * *
    (12) Geologic sequestration of carbon dioxide with enhanced oil 
recovery that is covered by subpart VV of this part.
* * * * *
    (h) If you capture a CO2 stream from a facility that is 
subject to this part and transfer CO2 to any facilities that 
are subject to subpart RR or VV of this part, you must:
    (1) Report the facility identification number associated with the 
annual GHG report for the facility that is the source of the captured 
CO2 stream;
    (2) Report each facility identification number associated with the 
annual GHG reports for each subpart RR and subpart VV facility to which 
CO2 is transferred; and
    (3) Report the annual quantity of CO2 in metric tons 
that is transferred to each subpart RR and subpart VV facility.
    (i) If you capture a CO2 stream at a facility with a DAC 
process unit, report the annual quantity of on-site and off-site 
electricity and heat generated for each DAC process unit as specified 
in paragraphs (i)(1) through (3) of this section. The quantities 
specified in paragraphs (i)(1) through (3) of this section must be 
provided per energy source if known and must represent the electricity 
and heat used for the DAC process unit starting with air intake and 
ending with the compressed CO2 stream (i.e., the 
CO2 stream ready for supply for commercial applications or, 
if maintaining custody of the stream, sequestration or injection of the 
stream underground).
    (1) Electricity excluding combined heat and power (CHP). If 
electricity is provided to a dedicated meter for the DAC process unit, 
report the annual quantity of electricity consumed, in megawatt hours 
(MWh), and the information in paragraph (i)(1)(i) or (ii) of this 
section.
    (i) If the electricity is sourced from a grid connection, report 
the following information:
    (A) State where the facility with the DAC process unit is located.
    (B) County where the facility with the DAC process unit is located.
    (C) Name of the electric utility company that supplied the 
electricity as shown on the last monthly bill issued by the utility 
company during the reporting period.
    (D) Name of the electric utility company that delivered the 
electricity. In states with regulated electric utility markets, this 
will generally be the same utility reported under paragraph 
(i)(1)(i)(C) of this section, but in states with deregulated electric 
utility markets, this may be a different utility company.
    (E) Annual quantity of electricity consumed in MWh, calculated as 
the sum of the total energy usage values specified in all billing 
statements received during the reporting year. Most customers will 
receive 12 monthly billing statements during the reporting year. Many 
utilities bill their customers per kilowatt-hour (kWh); usage values on 
bills that are based on kWh should be divided by 1,000 to report the 
usage in MWh as required under this paragraph (i)(1)(i)(E).
    (ii) If electricity is sourced from on-site or through a 
contractual mechanism for dedicated off-site generation, for each 
applicable energy source specified in paragraphs (i)(1)(ii)(A) through 
(G) of this section, report the annual quantity of electricity 
consumed, in MWh. If the on-site electricity source is natural gas, 
oil, or coal, also indicate whether flue gas is also captured by the 
DAC process unit.
    (A) Non-hydropower renewable sources including solar, wind, 
geothermal and tidal.
    (B) Hydropower.

[[Page 31944]]

    (C) Natural gas.
    (D) Oil.
    (E) Coal.
    (F) Nuclear.
    (G) Other.
    (2) Heat excluding CHP. For each applicable energy source specified 
in paragraphs (i)(2)(i) through (vii) of this section, report the 
annual quantity of heat, steam, or other forms of thermal energy 
sourced from on-site or through a contractual mechanism for dedicated 
off-site generation, in megajoules (MJ). If the on-site heat source is 
natural gas, oil, or coal, also indicate whether flue gas is also 
captured by the DAC process unit.
    (i) Solar.
    (ii) Geothermal.
    (iii) Natural gas.
    (iv) Oil.
    (v) Coal.
    (vi) Nuclear.
    (vii) Other.
    (3) CHP--(i) Electricity from CHP. If electricity from CHP is 
sourced from on-site or through a contractual mechanism for dedicated 
off-site generation, for each applicable energy source specified in 
paragraphs (i)(3)(i)(A) through (G) of this section, report the annual 
quantity consumed, in MWh. If the on-site electricity source for CHP is 
natural gas, oil, or coal, also indicate whether flue gas is also 
captured by the DAC process unit.
    (A) Non-hydropower renewable sources including solar, wind, 
geothermal and tidal.
    (B) Hydropower.
    (C) Natural gas.
    (D) Oil.
    (E) Coal.
    (F) Nuclear.
    (G) Other.
    (ii) Heat from CHP. For each applicable energy source specified in 
paragraphs (i)(3)(ii)(A) through (G) of this section, report the 
quantity of heat, steam, or other forms of thermal energy from CHP 
sourced from on-site or through a contractual mechanism for dedicated 
off-site generation, in MJ. If the on-site heat source is natural gas, 
oil, or coal, also indicate whether flue gas is also captured by the 
DAC process unit.
    (A) Solar.
    (B) Geothermal.
    (C) Natural gas.
    (D) Oil.
    (E) Coal.
    (F) Nuclear.
    (G) Other.

0
84. Amend Sec.  98.427 by revising paragraph (a) to read as follows:


Sec.  98.427   Records that must be retained.

* * * * *
    (a) The owner or operator of a facility containing production 
process units or DAC process units must retain quarterly records of 
captured or transferred CO2 streams and composition.
* * * * *

Subpart QQ--Importers and Exporters of Fluorinated Greenhouse Gases 
Contained in Pre-Charged Equipment or Closed-Cell Foams

0
85. Amend Sec.  98.436 by adding paragraphs (a)(7) and (b)(7) to read 
as follows:


Sec.  98.436   Data reporting requirements.

    (a) * * *
    (7) The Harmonized tariff system (HTS) code for each type of pre-
charged equipment or closed-cell foam imported.
    (b) * * *
    (7) The Schedule B code for each type of pre-charged equipment or 
closed-cell foam exported.

Subpart RR--Geologic Sequestration of Carbon Dioxide

0
86. Amend Sec.  98.449 by adding the definition ``Offshore'' in 
alphabetical order to read as follows:


Sec.  98.449  Definitions.

* * * * *
    Offshore means seaward of the terrestrial borders of the United 
States, including waters subject to the ebb and flow of the tide, as 
well as adjacent bays, lakes or other normally standing waters, and 
extending to the outer boundaries of the jurisdiction and control of 
the United States under the Outer Continental Shelf Lands Act.
* * * * *

0
87. Revise subpart SS consisting of Sec. Sec.  98.450 through 98.458 to 
read as follows:

Subpart SS--Electrical Equipment Manufacture or Refurbishment

Sec.
98.450 Definition of the source category.
98.451 Reporting threshold.
98.452 GHGs to report.
98.453 Calculating GHG emissions.
98.454 Monitoring and QA/QC requirements.
98.455 Procedures for estimating missing data.
98.456 Data reporting requirements.
98.457 Records that must be retained.
98.458 Definitions.


Sec.  98.450  Definition of the source category.

    The electrical equipment manufacturing or refurbishment category 
consists of processes that manufacture or refurbish gas-insulated 
substations, circuit breakers, other switchgear, gas-insulated lines, 
or power transformers (including gas-containing components of such 
equipment) containing fluorinated GHGs, including but not limited to 
sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs). The 
processes include equipment testing, installation, manufacturing, 
decommissioning and disposal, refurbishing, and storage in gas 
cylinders and other containers.


Sec.  98.451   Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an electrical equipment manufacturing or refurbishing process 
and the facility meets the requirements of Sec.  98.2(a)(2). To 
calculate total annual GHG emissions for comparison to the 25,000 
metric ton CO2e per year emission threshold in Sec.  
98.2(a)(2), follow the requirements of Sec.  98.2(b), with one 
exception. Instead of following the requirement of Sec.  98.453 to 
calculate emissions from electrical equipment manufacture or 
refurbishment, you must calculate emissions of each fluorinated GHG 
that is a component of a reportable insulating gas and then sum the 
emissions of each fluorinated GHG resulting from manufacturing and 
refurbishing electrical equipment using equation SS-1 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.059

Where:

E = Annual production process emissions for threshold applicability 
purposes (metric tons CO2e).
Pj = Total annual purchases of reportable insulating gas 
j (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j if reportable insulating gas j is a gas 
mixture. If not a mixture, use 1.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
EF = Emission factor for electrical transmission and distribution 
equipment (lbs emitted/lbs purchased). For all gases, use an 
emission factor of 0.1.

[[Page 31945]]

i = Fluorinated GHG contained in the electrical transmission and 
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.


Sec.  98.452  GHGs to report.

    (a) You must report emissions of each fluorinated GHG, including 
but not limited to SF6 and PFCs, at the facility level, except you are 
not required to report emissions of fluorinated GHGs that are 
components of insulating gases whose weighted average GWPs, as 
calculated in equation SS-2 to this section, are less than or equal to 
one. You are, however, required to report certain quantities of 
insulating gases whose weighted average GWPs are less than or equal to 
one as specified in Sec.  98.456(f), (g), (k) and (q) through (s). 
Annual emissions from the facility must include fluorinated GHG 
emissions from equipment that is installed at an off-site electric 
power transmission or distribution location whenever emissions from 
installation activities (e.g., filling) occur before the title to the 
equipment is transferred to the electric power transmission or 
distribution entity.
[GRAPHIC] [TIFF OMITTED] TR25AP24.060

Where:

GWPj = Weighted average GWP of insulating gas j.
GHGi,w = The weight fraction of GHG i in insulating gas 
j, expressed as a decimal. fraction. If GHG i is not part of a gas 
mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to 
subpart A of this part.
i = GHG contained in the electrical transmission and distribution 
equipment.

    (b) You must report CO2, N2O and 
CH4 emissions from each stationary combustion unit. You must 
calculate and report these emissions under subpart C of this part by 
following the requirements of subpart C of this part.


Sec.  98.453   Calculating GHG emissions.

    (a) For each electrical equipment manufacturer or refurbisher, 
estimate the annual emissions of each fluorinated GHG that is a 
component of any reportable insulating gas using the mass-balance 
approach in equation SS-3 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.061

Where:

User emissionsi = Annual emissions of each fluorinated 
GHG i (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j if insulating gas j is a gas mixture, 
expressed as a decimal fraction. If fluorinated GHG i is not part of 
a gas mixture, use a value of 1.0.
Decrease in Inventory of Reportable Insulating Gas j Inventory = 
(Pounds of reportable insulating gas j stored in containers at the 
beginning of the year)--(Pounds of reportable insulating gas j 
stored in containers at the end of the year).
Acquisitions of Reportable Insulating Gas j = (Pounds of reportable 
insulating gas j purchased from chemical producers or suppliers in 
bulk) + (Pounds of reportable insulating gas j returned by equipment 
users) + (Pounds of reportable insulating gas j returned to site 
after off-site recycling).
Disbursements of Reportable Insulating Gas j = (Pounds of reportable 
insulating gas j contained in new equipment delivered to customers) 
+ (Pounds of reportable insulating gas j delivered to equipment 
users in containers) + (Pounds of reportable insulating gas j 
returned to suppliers) + (Pounds of reportable insulating gas j sent 
off site for recycling) + (Pounds of reportable insulating gas j 
sent off-site for destruction).

    (b) [Reserved]
    (c) Estimate the disbursements of reportable insulating gas j sent 
to customers in new equipment or cylinders or sent off-site for other 
purposes including for recycling, for destruction or to be returned to 
suppliers using equation SS-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.062

Where:

DGHG = The annual disbursement of reportable insulating 
gas j sent to customers in new equipment or cylinders or sent off-
site for other purposes including for recycling, for destruction or 
to be returned to suppliers.
Qp = The mass of reportable insulating gas j charged into 
equipment or containers over the period p sent to customers or sent 
off-site for other purposes including for recycling, for destruction 
or to be returned to suppliers.
n = The number of periods in the year.

    (d) Estimate the mass of each insulating gas j disbursed to 
customers in new equipment or cylinders over the period p by monitoring 
the mass flow of each insulating gas j into the new equipment or 
cylinders using a flowmeter, or by weighing containers before and after 
gas from containers is used to fill equipment or cylinders, or by using 
the nameplate capacity of the equipment.
    (e) If the mass of insulating gas j disbursed to customers in new 
equipment or cylinders over the period p is estimated by weighing 
containers before and after gas from containers is used to fill 
equipment or cylinders, estimate this quantity using equation SS-5 to 
this section:

[[Page 31946]]

[GRAPHIC] [TIFF OMITTED] TR25AP24.063

Where:

Qp = The mass of insulating gas j charged into equipment 
or containers over the period p sent to customers or sent off-site 
for other purposes including for recycling, for destruction or to be 
returned to suppliers.
MB = The mass of the contents of the containers used to 
fill equipment or cylinders at the beginning of period p.
ME = The mass of the contents of the containers used to 
fill equipment or cylinders at the end of period p.
EL = The mass of insulating gas j emitted during the 
period p downstream of the containers used to fill equipment or 
cylinders and in cases where a flowmeter is used, downstream of the 
flowmeter during the period p (e.g., emissions from hoses or other 
flow lines that connect the container to the equipment or cylinder 
that is being filled).

    (f) If the mass of insulating gas j disbursed to customers in new 
equipment or cylinders over the period p is determined using a 
flowmeter, estimate this quantity using equation SS-6 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.064

Where:

Qp = The mass of insulating gas j charged into equipment 
or containers over the period p sent to customers or sent off-site 
for other purposes including for recycling, for destruction or to be 
returned to suppliers.
Mmr = The mass of insulating gas j that has flowed 
through the flowmeter during the period p.
EL = The mass of insulating gas j emitted during the 
period p downstream of the containers used to fill equipment or 
cylinders and in cases where a flowmeter is used, downstream of the 
flowmeter during the period p (e.g., emissions from hoses or other 
flow lines that connect the container to the equipment that is being 
filled).

    (g) Estimate the mass of insulating gas j emitted during the period 
p downstream of the containers used to fill equipment or cylinders 
(e.g., emissions from hoses or other flow lines that connect the 
container to the equipment or cylinder that is being filled) using 
equation SS-7 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.065

Where:

EL = The mass of insulating gas j emitted during the 
period p downstream of the containers used to fill equipment or 
cylinders and in cases where a flowmeter is used, downstream of the 
flowmeter during the period p (e.g., emissions from hoses or other 
flow lines that connect the container to the equipment or cylinder 
that is being filled).
FCi = The total number of fill operations over the period 
p for the valve-hose combination Ci.
EFCi = The emission factor for the valve-hose combination 
Ci.
n=The number of different valve-hose combinations C used during the 
period p.

    (h) If the mass of insulating gas j disbursed to customers in new 
equipment or cylinders over the period p is determined by using the 
nameplate capacity, or by using the nameplate capacity of the equipment 
and calculating the partial shipping charge, use the methods in either 
paragraph (h)(1) or (2) of this section.
    (1) Determine the equipment's actual nameplate capacity, by 
measuring the nameplate capacities of a representative sample of each 
make and model and calculating the mean value for each make and model 
as specified at Sec.  98.454(f).
    (2) If equipment is shipped with a partial charge, calculate the 
partial shipping charge by multiplying the nameplate capacity of the 
equipment by the ratio of the densities of the partial charge to the 
full charge.
    (i) Estimate the annual emissions of reportable insulating gas j 
from the equipment that is installed at an off-site electric power 
transmission or distribution location before the title to the equipment 
is transferred by using equation SS-8 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.066

Where:

EI = Total annual emissions of reportable insulating gas j from 
equipment installation at electric transmission or distribution 
facilities.
GHGi,w = The weight fraction of fluorinated GHG i in 
reportable insulating gas j if reportable insulating gas j is a gas 
mixture, expressed as a decimal fraction. If the GHG i is not part 
of a gas mixture, use a value of 1.0.
MF = The total annual mass of reportable insulating gas 
j, in pounds, used to fill equipment during equipment installation 
at electric transmission or distribution facilities.
MC = The total annual mass of reportable insulating gas 
j, in pounds, used to charge the equipment prior to leaving the 
electrical equipment manufacturer facility.
NI = The total annual nameplate capacity of the 
equipment, in pounds, installed at electric transmission or 
distribution facilities.


Sec.  98.454   Monitoring and QA/QC requirements.

    (a) [Reserved]
    (b) Ensure that all the quantities required by the equations of 
this subpart have been measured using either flowmeters with an 
accuracy and precision of 1 percent of full scale or better 
or scales with an accuracy and precision of 1 percent of 
the filled weight (gas plus tare) of the containers of each reportable 
insulating gas that are typically weighed on the scale. For scales that 
are generally used to weigh cylinders containing 115 pounds of gas when 
full, this equates to 1 percent of the sum of 115 pounds 
and approximately 120 pounds tare, or slightly more than 2 
pounds. Account for the tare weights of the containers. You may accept 
gas masses or weights provided by the gas supplier (e.g., for the 
contents of cylinders containing

[[Page 31947]]

new gas or for the heels remaining in cylinders returned to the gas 
supplier) if the supplier provides documentation verifying that 
accuracy standards are met; however, you remain responsible for the 
accuracy of these masses and weights under this subpart.
    (c) All flow meters, weigh scales, and combinations of volumetric 
and density measures that are used to measure or calculate quantities 
under this subpart must be calibrated using calibration procedures 
specified by the flowmeter, scale, volumetric or density measure 
equipment manufacturer. Calibration must be performed prior to the 
first reporting year. After the initial calibration, recalibration must 
be performed at the minimum frequency specified by the manufacturer.
    (d) For purposes of equation SS-7 to Sec.  98.453, the emission 
factor for the valve-hose combination (EFC) must be estimated using 
measurements and/or engineering assessments or calculations based on 
chemical engineering principles or physical or chemical laws or 
properties. Such assessments or calculations may be based on, as 
applicable, the internal volume of hose or line that is open to the 
atmosphere during coupling and decoupling activities, the internal 
pressure of the hose or line, the time the hose or line is open to the 
atmosphere during coupling and decoupling activities, the frequency 
with which the hose or line is purged and the flow rate during purges. 
You must develop a value for EFc (or use an industry-developed value) 
for each combination of hose and valve fitting, to use in equation SS-7 
to Sec.  98.453. The value for EFC must be determined for each 
combination of hose and valve fitting of a given diameter or size. The 
calculation must be recalculated annually to account for changes to the 
specifications of the valves or hoses that may occur throughout the 
year.
    (e) Electrical equipment manufacturers and refurbishers must 
account for emissions of each reportable insulating gas that occur as a 
result of unexpected events or accidental losses, such as a 
malfunctioning hose or leak in the flow line, during the filling of 
equipment or containers for disbursement by including these losses in 
the estimated mass of each reportable insulating gas emitted downstream 
of the container or flowmeter during the period p.
    (f) If the mass of each reportable insulating gas j disbursed to 
customers in new equipment over the period p is determined by assuming 
that it is equal to the equipment's nameplate capacity or, in cases 
where equipment is shipped with a partial charge, equal to its partial 
shipping charge, equipment samples for conducting the nameplate 
capacity tests must be selected using the following stratified sampling 
strategy in this paragraph (f). For each make and model, group the 
measurement conditions to reflect predictable variability in the 
facility's filling practices and conditions (e.g., temperatures at 
which equipment is filled). Then, independently select equipment 
samples at random from each make and model under each group of 
conditions. To account for variability, a certain number of these 
measurements must be performed to develop a robust and representative 
average nameplate capacity (or shipping charge) for each make, model, 
and group of conditions. A Student T distribution calculation should be 
conducted to determine how many samples are needed for each make, 
model, and group of conditions as a function of the relative standard 
deviation of the sample measurements. To determine a sufficiently 
precise estimate of the nameplate capacity, the number of measurements 
required must be calculated to achieve a precision of one percent of 
the true mean, using a 95 percent confidence interval. To estimate the 
nameplate capacity for a given make and model, you must use the lowest 
mean value among the different groups of conditions, or provide 
justification for the use of a different mean value for the group of 
conditions that represents the typical practices and conditions for 
that make and model. Measurements can be conducted using SF6, another 
gas, or a liquid. Re-measurement of nameplate capacities should be 
conducted every five years to reflect cumulative changes in 
manufacturing methods and conditions over time.
    (g) Ensure the following QA/QC methods are employed throughout the 
year:
    (1) Procedures are in place and followed to track and weigh all 
cylinders or other containers at the beginning and end of the year.
    (2) [Reserved]
    (h) You must adhere to the following QA/QC methods for reviewing 
the completeness and accuracy of reporting:
    (1) Review inputs to equation SS-3 to Sec.  98.453 to ensure inputs 
and outputs to the company's system are included.
    (2) Do not enter negative inputs and confirm that negative 
emissions are not calculated. However, the decrease in the inventory 
for each reportable insulating gas may be calculated as negative.
    (3) Ensure that for each reportable insulating gas, the beginning-
of-year inventory matches the end-of-year inventory from the previous 
year.
    (4) Ensure that for each reportable insulating gas, in addition to 
the reportable insulating gas purchased from bulk gas distributors, the 
reportable insulating gas returned from equipment users with or inside 
equipment and the reportable insulating gas returned from off-site 
recycling are also accounted for among the total additions.


Sec.  98.455   Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Replace missing data, if needed, 
based on data from similar manufacturing operations, and from similar 
equipment testing and decommissioning activities for which data are 
available.


Sec.  98.456   Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each chemical 
at the facility level:
    (a) Pounds of each reportable insulating gas stored in containers 
at the beginning of the year.
    (b) Pounds of each reportable insulating gas stored in containers 
at the end of the year.
    (c) Pounds of each reportable insulating gas purchased in bulk.
    (d) Pounds of each reportable insulating gas returned by equipment 
users with or inside equipment.
    (e) Pounds of each reportable insulating gas returned to site from 
off site after recycling.
    (f) Pounds of each insulating gas inside new equipment delivered to 
customers.
    (g) Pounds of each insulating gas delivered to equipment users in 
containers.
    (h) Pounds of each reportable insulating gas returned to suppliers.
    (i) Pounds of each reportable insulating gas sent off site for 
destruction.
    (j) Pounds of each reportable insulating gas sent off site to be 
recycled.
    (k) The nameplate capacity of the equipment, in pounds, delivered 
to customers with each insulating gas inside, if different from the 
quantity in paragraph (f) of this section.
    (l) A description of the engineering methods and calculations used 
to determine emissions from hoses or other flow lines that connect the 
container to the equipment that is being filled.
    (m) The values for EFci of equation SS-7 to Sec.  98.453 
for each hose and valve combination and the associated valve fitting 
sizes and hose diameters.

[[Page 31948]]

    (n) The total number of fill operations for each hose and valve 
combination, or, FCi of equation SS-7 to Sec.  98.453.
    (o) If the mass of each reportable insulating gas disbursed to 
customers in new equipment over the period p is determined according to 
the methods required in Sec.  98.453(h), report the mean value of 
nameplate capacity in pounds for each make, model, and group of 
conditions.
    (p) If the mass of each reportable insulating gas disbursed to 
customers in new equipment over the period p is determined according to 
the methods required in Sec.  98.453(h), report the number of samples 
and the upper and lower bounds on the 95-percent confidence interval 
for each make, model, and group of conditions.
    (q) Pounds of each insulating gas used to fill equipment at off-
site electric power transmission or distribution locations, or MF, of 
equation SS-8 to Sec.  98.453.
    (r) Pounds of each insulating gas used to charge the equipment 
prior to leaving the electrical equipment manufacturer or refurbishment 
facility, or MC, of equation SS-8 to Sec.  98.453.
    (s) The nameplate capacity of the equipment, in pounds, installed 
at off-site electric power transmission or distribution locations used 
to determine emissions from installation, or NI, of equation 
SS-8 to Sec.  98.453.
    (t) For any missing data, you must report the reason the data were 
missing, the parameters for which the data were missing, the substitute 
parameters used to estimate emissions in their absence, and the 
quantity of emissions thereby estimated.
    (u) For each insulating gas reported in paragraphs (a) through (j) 
and (o) through (r) of this section, an ID number or other appropriate 
descriptor unique to that insulating gas.
    (v) For each ID number or descriptor reported in paragraph (u) of 
this section for each unique insulating gas, the name (as required in 
Sec.  98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas 
in the insulating gas.


Sec.  98.457  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) All information reported and listed in Sec.  98.456.
    (b) Accuracy certifications and calibration records for all scales 
and monitoring equipment, including the method or manufacturer's 
specification used for calibration.
    (c) Certifications of the quantity of gas, in pounds, charged into 
equipment at the electrical equipment manufacturer or refurbishment 
facility as well as the actual quantity of gas, in pounds, charged into 
equipment at installation.
    (d) Check-out and weigh-in sheets and procedures for cylinders.
    (e) Residual gas amounts, in pounds, in cylinders sent back to 
suppliers.
    (f) Invoices for gas purchases and sales.
    (g) GHG Monitoring Plans, as described in Sec.  98.3(g)(5), must be 
completed by April 1, 2011.


Sec.  98.458   Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the CAA and subpart A of this part.
    Insulating gas, for the purposes of this subpart, means any 
fluorinated GHG or fluorinated GHG mixture, including but not limited 
to SF6 and PFCs, that is used as an insulating and/or arc-
quenching gas in electrical equipment.
    Reportable insulating gas, for purposes of this subpart, means an 
insulating gas whose weighted average GWP, as calculated in equation 
SS-2 to Sec.  98.452, is greater than one. A fluorinated GHG that makes 
up either part or all of a reportable insulating gas is considered to 
be a component of the reportable insulating gas.

Subpart UU--Injection of Carbon Dioxide

0
88. Revise and republish Sec.  98.470 to read as follows:


Sec.  98.470   Definition of the source category.

    (a) The injection of carbon dioxide (CO2) source 
category comprises any well or group of wells that inject a 
CO2 stream into the subsurface.
    (b) If you report under subpart RR of this part for a well or group 
of wells, you shall not report under this subpart for that well or 
group of wells.
    (c) If you report under subpart VV of this part for a well or group 
of wells, you shall not report under this subpart for that well or 
group of wells. If you previously met the source category definition 
for subpart UU of this part for a project where CO2 is 
injected in enhanced recovery operations for oil and other hydrocarbons 
(CO2-EOR) and then began using the standard designated as 
CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.  98.7) such 
that you met the definition of the source category for subpart VV 
during a reporting year, you must report under subpart UU for the 
portion of the year before you began using CSA/ANSI ISO 27916:19 and 
report under subpart VV for the portion of the year after you began 
using CSA/ANSI ISO 27916:19.
    (d) A facility that is subject to this part only because it is 
subject to subpart UU of this part is not required to report emissions 
under subpart C of this part or any other subpart listed in Sec.  
98.2(a)(1) or (2).

0
89. Add subpart VV consisting of Sec. Sec.  98.480 through 98.489, 
subpart WW consisting of Sec. Sec.  98.490 through 98.498, subpart XX 
consisting of Sec. Sec.  98.500 through 98.508, subpart YY consisting 
of Sec. Sec.  98.510 through 98.518, and subpart ZZ consisting of 
Sec. Sec.  98.520 through 98.528 to part 98 to read as follows:

Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced 
Oil Recovery Using ISO 27916

Sec.
98.480 Definition of the source category.
98.481 Reporting threshold.
98.482 GHGs to report.
98.483 Calculating CO2 geologic sequestration.
98.484 Monitoring and QA/QC requirements.
98.485 Procedures for estimating missing data.
98.486 Data reporting requirements.
98.487 Records that must be retained.
98.488 EOR Operations Management Plan.
98.489 Definitions.


Sec.  98.480  Definition of the source category.

    (a) This source category pertains to carbon dioxide 
(CO2) that is injected in enhanced recovery operations for 
oil and other hydrocarbons (CO2-EOR) in which all of the 
following apply:
    (1) You are using the standard designated as CSA/ANSI ISO 27916:19, 
(incorporated by reference, see Sec.  98.7) as a method of quantifying 
geologic sequestration of CO2 in association with EOR 
operations.
    (2) You are not reporting under subpart RR of this part.
    (b) This source category does not include wells permitted as Class 
VI under the Underground Injection Control program.
    (c) If you are subject to only this subpart, you are not required 
to report emissions under subpart C of this part or any other subpart 
listed in Sec.  98.2(a)(1) or (2).


Sec.  98.481   Reporting threshold.

    (a) You must report under this subpart if your CO2-EOR 
project uses CSA/ANSI ISO 27916:19 (incorporated by reference, see 
Sec.  98.7) as a method of quantifying geologic sequestration of 
CO2 in association with CO2-EOR operations. There 
is no threshold for reporting.
    (b) The requirements of Sec.  98.2(i) do not apply to this subpart. 
Once a CO2-EOR project becomes subject to the

[[Page 31949]]

requirements of this subpart, you must continue for each year 
thereafter to comply with all requirements of this subpart, including 
the requirement to submit annual reports until the facility has met the 
requirements of paragraphs (b)(1) and (2) of this section and submitted 
a notification to discontinue reporting according to paragraph (b)(3) 
of this section.
    (1) Discontinuation of reporting under this subpart must follow the 
requirements set forth under Clause 10 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7).
    (2) CO2-EOR project termination is completed when all of 
the following occur:
    (i) Cessation of CO2 injection.
    (ii) Cessation of hydrocarbon production from the project 
reservoir; and
    (iii) Wells are plugged and abandoned unless otherwise required by 
the appropriate regulatory authority.
    (3) You must notify the Administrator of your intent to cease 
reporting and provide a copy of the CO2-EOR project 
termination documentation.
    (c) If you previously met the source category definition for 
subpart UU of this part for your CO2-EOR project and then 
began using CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.  
98.7) as a method of quantifying geologic sequestration of 
CO2 in association with CO2-EOR operations during 
a reporting year, you must report under subpart UU of this part for the 
portion of the year before you began using CSA/ANSI ISO 27916:19 and 
report under subpart VV for the portion of the year after you began 
using CSA/ANSI ISO 27916:19.


Sec.  98.482  GHGs to report.

    You must report the following from Clause 8 of CSA/ANSI ISO 
27916:19 (incorporated by reference, see Sec.  98.7):
    (a) The mass of CO2 received by the CO2-EOR 
project.
    (b) The mass of CO2 loss from the CO2-EOR 
project operations.
    (c) The mass of native CO2 produced and captured.
    (d) The mass of CO2 produced and sent off-site.
    (e) The mass of CO2 loss from the EOR complex.
    (f) The mass of CO2 stored in association with 
CO2-EOR.


Sec.  98.483  Calculating CO2 geologic sequestration.

    You must calculate CO2 sequestered using the following 
quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7).
    (a) You must calculate the mass of CO2 stored in 
association with CO2-EOR (mstored) in the 
reporting year by subtracting the mass of CO2 loss from 
operations and the mass of CO2 loss from the EOR complex 
from the total mass of CO2 input (as specified in equation 1 
to this paragraph (a)).
Equation 1 to paragraph (a)
mstored = minput-mloss operations-
mloss EOR complex

Where:

mstored = The annual quantity of associated storage in 
metric tons of CO2 mass.
minput = The total mass of CO2 
mreceived by the EOR project plus mnative (see 
Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see 
Sec.  98.7) and paragraph (c) of this section), metric tons. Native 
CO2 produced and captured in the CO2-EOR 
project (mnative) can be quantified and included in 
minput.
mloss operations = The total mass of CO2 loss 
from project operations (see Clauses 8.4.1 through 8.4.5 of CSA/ANSI 
ISO 27916:19 (incorporated by reference, see Sec.  98.7) and 
paragraph (d) of this section), metric tons.
mloss EOR complex = The total mass of CO2 loss 
from the EOR complex (see Clause 8.4.6 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7)), metric tons.

    (b) The manner by which associated storage is quantified must 
assure completeness and preclude double counting. The annual mass of 
CO2 that is recycled and reinjected into the EOR complex 
must not be quantified as associated storage. Loss from the 
CO2 recycling facilities must be quantified.
    (c) You must quantify the total mass of CO2 input 
(minput) in the reporting year according to paragraphs 
(g)(1) through (3) of this section.
    (1) You must include the total mass of CO2 received at 
the custody transfer meter by the CO2-EOR project 
(mreceived).
    (2) The CO2 stream received (including CO2 
transferred from another CO2-EOR project) must be metered.
    (i) The native CO2 recovered and included as 
mnative must be documented.
    (ii) CO2 delivered to multiple CO2-EOR 
projects must be allocated among those CO2-EOR projects.
    (3) The sum of the quantities of allocated CO2 must not 
exceed the total quantities of CO2 received.
    (d) You must calculate the total mass of CO2 from 
project operations (mloss operations) in the reporting year 
as specified in equation 2 to this paragraph (d).
Equation 2 to paragraph (d)
[GRAPHIC] [TIFF OMITTED] TR25AP24.067

Where:

mloss leakage facilities = Loss of CO2 due to 
leakage from production, handling, and recycling CO2-EOR 
facilities (infrastructure including wellheads), metric tons.
mloss vent/flare = Loss of CO2 from venting/
flaring from production operations, metric tons.
mloss entrained = Loss of CO2 due to 
entrainment within produced gas/oil/water when this CO2 
is not separated and reinjected, metric tons.
mloss transfer=Loss of CO2 due to any transfer 
of CO2 outside the CO2-EOR project, metric 
tons. You must quantify any CO2 that is subsequently 
produced from the EOR complex and transferred offsite.


Sec.  98.484  Monitoring and QA/QC requirements.

    You must use the applicable monitoring and quality assurance 
requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7).


Sec.  98.485   Procedures for estimating missing data.

    Whenever the value of a parameter is unavailable or the quality 
assurance procedures set forth in Sec.  98.484 cannot be followed, you 
must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO 
27916:19 (incorporated by reference, see Sec.  98.7).


Sec.  98.486   Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), the 
annual report shall contain the following information, as applicable:
    (a) The annual quantity of associated storage in metric tons of 
CO2 (mstored).
    (b) The density of CO2 if volumetric units are converted 
to mass in order to be reported for annual quantity of CO2 
stored.
    (c) The annual quantity of CO2 input (minput) 
and the information in paragraphs (c)(1) and (2) of this section.
    (1) The annual total mass of CO2 received at the custody 
transfer meter by the CO2-EOR project, including 
CO2

[[Page 31950]]

transferred from another CO2-EOR project 
(mreceived).
    (2) The annual mass of native CO2 produced and captured 
in the CO2-EOR project (mnative).
    (d) The annual mass of CO2 that is recycled and 
reinjected into the EOR complex.
    (e) The annual total mass of CO2 loss from project 
operations (mloss operations), and the information in 
paragraphs (e)(1) through (4) of this section.
    (1) Loss of CO2 due to leakage from production, 
handling, and recycling CO2-EOR facilities (infrastructure 
including wellheads) (mloss leakage facilities).
    (2) Loss of CO2 from venting/flaring from production 
operations (mloss vent/flare).
    (3) Loss of CO2 due to entrainment within produced gas/
oil/water when this CO2 is not separated and reinjected 
(mloss entrained).
    (4) Loss of CO2 due to any transfer of CO2 
outside the CO2-EOR project (mloss transfer).
    (f) The total mass of CO2 loss from the EOR complex 
(mloss EOR complex).
    (g) Annual documentation that contains the following components as 
described in Clause 4.4 of CSA/ANSI ISO 27916:19 (incorporated by 
reference, see Sec.  98.7):
    (1) The formulas used to quantify the annual mass of associated 
storage, including the mass of CO2 delivered to the 
CO2-EOR project and losses during the period covered by the 
documentation (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7)).
    (2) The methods used to estimate missing data and the amounts 
estimated as described in Clause 9.2 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7).
    (3) The approach and method for quantification utilized by the 
operator, including accuracy, precision, and uncertainties (see Clause 
8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see 
Sec.  98.7)).
    (4) A statement describing the nature of validation or verification 
including the date of review, process, findings, and responsible person 
or entity.
    (5) Source of each CO2 stream quantified as associated 
storage (see Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by 
reference, see Sec.  98.7)).
    (6) A description of the procedures used to detect and characterize 
the total CO2 leakage from the EOR complex.
    (7) If only the mass of anthropogenic CO2 is considered 
for mstored, a description of the derivation and application of 
anthropogenic CO2 allocation ratios for all the terms 
described in Clauses 8.1 to 8.4.6 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7).
    (8) Any documentation provided by a qualified independent engineer 
or geologist, who certifies that the documentation provided, including 
the mass balance calculations as well as information regarding 
monitoring and containment assurance, is accurate and complete.
    (h) Any changes made within the reporting year to containment 
assurance and monitoring approaches and procedures in the EOR 
operations management plan.


Sec.  98.487   Records that must be retained.

    You must follow the record retention requirements specified by 
Sec.  98.3(g). In addition to the records required by Sec.  98.3(g), 
you must comply with the record retention requirements in Clause 9.1 of 
CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.  98.7).


Sec.  98.488   EOR Operations Management Plan.

    (a) You must prepare and update, as necessary, a general EOR 
operations management plan that provides a description of the EOR 
complex and engineered system (see Clause 4.3(a) of CSA/ANSI ISO 
27916:19 (incorporated by reference, see Sec.  98.7)), establishes that 
the EOR complex is adequate to provide safe, long-term containment of 
CO2, and includes site-specific and other information 
including:
    (1) Geologic characterization of the EOR complex.
    (2) A description of the facilities within the CO2-EOR 
project.
    (3) A description of all wells and other engineered features in the 
CO2-EOR project.
    (4) The operations history of the project reservoir.
    (5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO 
27916:19 (incorporated by reference, see Sec.  98.7).
    (b) You must prepare initial documentation at the beginning of the 
quantification period, and include the following as described in the 
EOR operations management plan:
    (1) A description of the EOR complex and engineered systems (see 
Clause 5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.  
98.7)).
    (2) The initial containment assurance (see Clause 6.1.2 of CSA/ANSI 
ISO 27916:19 (incorporated by reference, see Sec.  98.7)).
    (3) The monitoring program (see Clause 6.2 of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7)).
    (4) The quantification method to be used (see Clause 8 and Annex B 
of CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.  98.7)).
    (5) The total mass of previously injected CO2 (if any) 
within the EOR complex at the beginning of the CO2-EOR 
project (see Clause 8.5 and Annex B of CSA/ANSI ISO 27916:19 
(incorporated by reference, see Sec.  98.7)).
    (c) The EOR operation management plan in paragraph (a) of this 
section and initial documentation in paragraph (b) of this section must 
be submitted to the Administrator with the annual report covering the 
first reporting year that the facility reports under this subpart. In 
addition, any documentation provided by a qualified independent 
engineer or geologist, who certifies that the documentation provided is 
accurate and complete, must also be provided to the Administrator.
    (d) If the EOR operations management plan is updated, the updated 
EOR management plan must be submitted to the Administrator with the 
annual report covering the first reporting year for which the updated 
EOR operation management plan is applicable.


Sec.  98.489  Definitions.

    Except as provided in paragraphs (a) and (b) of this section, all 
terms used in this subpart have the same meaning given in the Clean Air 
Act and subpart A of this part.
    Additional terms and definitions are provided in Clause 3 of CSA/
ANSI ISO 27916:19 (incorporated by reference, see Sec.  98.7).

Subpart WW--Coke Calciners

Sec.
98.490 Definition of the source category.
98.491 Reporting threshold.
98.492 GHGs to report.
98.493 Calculating GHG emissions.
98.494 Monitoring and QA/QC requirements.
98.495 Procedures for estimating missing data.
98.496 Data reporting requirements.
98.497 Records that must be retained.
98.498 Definitions.


Sec.  98.490  Definition of the source category.

    (a) A coke calciner is a process unit that heats petroleum coke to 
high temperatures for the purpose of removing impurities or volatile 
substances in the petroleum coke feedstock.
    (b) This source category consists of rotary kilns, rotary hearth 
furnaces, or similar process units used to calcine petroleum coke and 
also includes afterburners or other emission control systems used to 
treat the coke calcining unit's process exhaust gas.

[[Page 31951]]

Sec.  98.491  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a coke calciner and the facility meets the requirements of 
either Sec.  98.2(a)(1) or (2).


Sec.  98.492   GHGs to report.

    You must report:
    (a) CO2, CH4, and N2O emissions 
from each coke calcining unit under this subpart.
    (b) CO2, CH4, and N2O emissions 
from auxiliary fuel used in the coke calcining unit and afterburner, if 
applicable, or other control system used to treat the coke calcining 
unit's process off-gas under subpart C of this part by following the 
requirements of subpart C.


Sec.  98.493   Calculating GHG emissions.

    (a) Calculate GHG emissions required to be reported in Sec.  
98.492(a) using the applicable methods in paragraph (b) of this 
section.
    (b) For each coke calcining unit, calculate GHG emissions according 
to the applicable provisions in paragraphs (b)(1) through (4) of this 
section.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part, you must calculate and 
report CO2 emissions under this subpart by following the 
Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part. Auxiliary 
fuel use CO2 emissions should be calculated in accordance 
with subpart C of this part and subtracted from the CO2 CEMS 
emissions to determine process CO2 emissions. Other coke 
calcining units must either install a CEMS that complies with the Tier 
4 Calculation Methodology in subpart C of this part or follow the 
requirements of paragraph (b)(2) of this section.
    (2) Calculate the CO2 emissions from the coke calcining 
unit using monthly measurements and equation 1 to this paragraph 
(b)(2).
Equation 1 to paragraph (b)(2)
[GRAPHIC] [TIFF OMITTED] TR25AP24.068

Where:

CO2 = Annual CO2 emissions (metric tons 
CO2/year).
m = Month index.
Min,m = Mass of green coke fed to the coke calcining unit 
in month ``m'' from facility records (metric tons/year).
CCGC.m = Mass fraction carbon content of green coke fed 
to the coke calcining unit from facility measurement data in month 
``m'' (metric ton carbon/metric ton green coke). If measurements are 
made more frequently than monthly, determine the monthly average as 
the arithmetic average for all measurements made during the calendar 
month.
Mout,m = Mass of marketable petroleum coke produced by 
the coke calcining unit in month ``m'' from facility records (metric 
tons petroleum coke/year).
Mdust,m = Mass of petroleum coke dust removed from the 
process through the dust collection system of the coke calcining 
unit in month ``m'' from facility records (metric ton petroleum coke 
dust/year). For coke calcining units that recycle the collected 
dust, the mass of coke dust removed from the process is the mass of 
coke dust collected less the mass of coke dust recycled to the 
process.
CCMPC,m = Mass fraction carbon content of marketable 
petroleum coke produced by the coke calcining unit in month ``m'' 
from facility measurement data (metric ton carbon/metric ton 
petroleum coke). If measurements are made more frequently than 
monthly, determine the monthly average as the arithmetic average for 
all measurements made during the calendar month.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).

    (3) Calculate CH4 emissions using equation 2 to this paragraph 
(b)(3).
Equation 2 to paragraph (b)(3)
[GRAPHIC] [TIFF OMITTED] TR25AP24.069

Where:

CH4 = Annual methane emissions (metric tons 
CH4/year).
CO2 = Annual CO2 emissions calculated in 
paragraph (b)(1) or (2) of this section, as applicable (metric tons 
CO2/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from table C-1 to subpart C of this part (kg 
CO2/MMBtu).
EmF2 = Default CH4 emission factor for 
``Petroleum Products (All fuel types in table C-1)'' from table C-2 
to subpart C of this part (kg CH4/MMBtu).

    (4) Calculate N2O emissions using equation 3 to this 
paragraph (b)(4).
Equation 3 to paragraph (b)(4)
[GRAPHIC] [TIFF OMITTED] TR25AP24.070

Where:

N2O = Annual nitrous oxide emissions (metric tons 
N2O/year).
CO2 = Annual CO2 emissions calculated in 
paragraph (b)(1) or (2) of this section, as applicable (metric tons 
CO2/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from table C-1 to subpart C of this part (kg 
CO2/MMBtu).
EmF3 = Default N2O emission factor for 
``Petroleum Products (All fuel types in table C-1)'' from table C-2 
to subpart C of this part (kg N2O/MMBtu).


Sec.  98.494  Monitoring and QA/QC requirements.

    (a) Flow meters, gas composition monitors, and heating value 
monitors that are associated with sources that use a CEMS to measure 
CO2 emissions according to subpart C of this part or that 
are associated with stationary combustion sources must meet the 
applicable monitoring and QA/QC requirements in Sec.  98.34.
    (b) Determine the mass of petroleum coke monthly as required by 
equation 1 to Sec.  98.493(b)(2) using mass measurement equipment 
meeting the requirements for commercial weighing equipment as described 
in NIST HB 44-2023 (incorporated by reference, see Sec.  98.7). 
Calibrate the measurement device according to the procedures specified 
by NIST HB 44-2023 (incorporated by reference, see Sec.  98.7) or the 
procedures specified by the

[[Page 31952]]

manufacturer. Recalibrate either biennially or at the minimum frequency 
specified by the manufacturer.
    (c) Determine the carbon content of petroleum coke as required by 
equation 1 Sec.  98.493(b)(2) using any one of the following methods. 
Calibrate the measurement device according to procedures specified by 
the method or procedures specified by the measurement device 
manufacturer.
    (1) ASTM D3176-15 (incorporated by reference, see Sec.  98.7).
    (2) ASTM D5291-16 (incorporated by reference, see Sec.  98.7).
    (3) ASTM D5373-21 (incorporated by reference, see Sec.  98.7).
    (d) The owner or operator must document the procedures used to 
ensure the accuracy of the monitoring systems used including but not 
limited to calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded.


Sec.  98.495   Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., concentrations, flow rates, 
fuel heating values, carbon content values). Therefore, whenever a 
quality-assured value of a required parameter is unavailable (e.g., if 
a CEMS malfunctions during unit operation or if a required sample is 
not taken), a substitute data value for the missing parameter must be 
used in the calculations.
    (a) For missing auxiliary fuel use data, use the missing data 
procedures in subpart C of this part.
    (b) For each missing value of mass or carbon content of coke, 
substitute the arithmetic average of the quality-assured values of that 
parameter immediately preceding and immediately following the missing 
data incident. If the ``after'' value is not obtained by the end of the 
reporting year, you may use the ``before'' value for the missing data 
substitution. If, for a particular parameter, no quality-assured data 
are available prior to the missing data incident, the substitute data 
value must be the first quality-assured value obtained after the 
missing data period.
    (c) For missing CEMS data, you must use the missing data procedures 
in Sec.  98.35.


Sec.  98.496   Data reporting requirements.

    In addition to the reporting requirements of Sec.  98.3(c), you 
must report the information specified in paragraphs (a) through (i) of 
this section for each coke calcining unit.
    (a) The unit ID number (if applicable).
    (b) Maximum rated throughput of the unit, in metric tons coke 
calcined/stream day.
    (c) The calculated CO2, CH4, and 
N2O annual process emissions, expressed in metric tons of 
each pollutant emitted.
    (d) A description of the method used to calculate the 
CO2 emissions for each unit (e.g., CEMS or equation 1 to 
Sec.  98.493(b)(2)).
    (e) Annual mass of green coke fed to the coke calcining unit from 
facility records (metric tons/year).
    (f) Annual mass of marketable petroleum coke produced by the coke 
calcining unit from facility records (metric tons/year).
    (g) Annual mass of petroleum coke dust removed from the process 
through the dust collection system of the coke calcining unit from 
facility records (metric tons/year) and an indication of whether coke 
dust is recycled to the unit (e.g., all dust is recycled, a portion of 
the dust is recycled, or none of the dust is recycled).
    (h) Annual average mass fraction carbon content of green coke fed 
to the coke calcining unit from facility measurement data (metric tons 
C per metric ton green coke).
    (i) Annual average mass fraction carbon content of marketable 
petroleum coke produced by the coke calcining unit from facility 
measurement data (metric tons C per metric ton petroleum coke).


Sec.  98.497   Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section.
    (a) The records of all parameters monitored under Sec.  98.494.
    (b) The applicable verification software records as identified in 
this paragraph (b). You must keep a record of the file generated by the 
verification software specified in Sec.  98.5(b) for the applicable 
data specified in paragraphs (b)(1) through (5) of this section. 
Retention of this file satisfies the recordkeeping requirement for the 
data in paragraphs (b)(1) through (5) of this section.
    (1) Monthly mass of green coke fed to the coke calcining unit from 
facility records (metric tons/year) (equation 1 to Sec.  98.493(b)(2)).
    (2) Monthly mass of marketable petroleum coke produced by the coke 
calcining unit from facility records (metric tons/year) (equation 1 to 
Sec.  98.493(b)(2)).
    (3) Monthly mass of petroleum coke dust removed from the process 
through the dust collection system of the coke calcining unit from 
facility records (metric tons/year) (equation 1 to Sec.  98.493(b)(2)).
    (4) Average monthly mass fraction carbon content of green coke fed 
to the coke calcining unit from facility measurement data (metric tons 
C per metric ton green coke) (equation 1 to Sec.  98.493(b)(2)).
    (5) Average monthly mass fraction carbon content of marketable 
petroleum coke produced by the coke calcining unit from facility 
measurement data (metric tons C per metric ton petroleum coke) 
(equation 1 to Sec.  98.493(b)(2)).


Sec.  98.498  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart XX--Calcium Carbide Production

Sec.
98.500 Definition of the source category.
98.501 Reporting threshold.
98.502 GHGs to report.
98.503 Calculating GHG emissions.
98.504 Monitoring and QA/QC requirements.
98.505 Procedures for estimating missing data.
98.506 Data reporting requirements.
98.507 Records that must be retained.
98.508 Definitions.


Sec.  98.500   Definition of the source category.

    The calcium carbide production source category consists of any 
facility that produces calcium carbide.


Sec.  98.501  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a calcium carbide production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.502  GHGs to report.

    You must report:
    (a) Process CO2 emissions from each calcium carbide 
process unit or furnace used for the production of calcium carbide.
    (b) CO2, CH4, and N2O emissions 
from each stationary combustion unit following the requirements of 
subpart C of this part. You must report these emissions under subpart C 
of this part by following the requirements of subpart C.


Sec.  98.503   Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each calcium carbide process unit not subject to 
paragraph (c) of this section using the procedures in either paragraph 
(a) or (b) of this section.
    (a) Calculate and report under this subpart the combined process 
and

[[Page 31953]]

combustion CO2 emissions by operating and maintaining CEMS 
according to the Tier 4 Calculation Methodology in Sec.  98.33(a)(4) 
and all associated requirements for Tier 4 in subpart C of this part.
    (b) Calculate and report under this subpart the annual process 
CO2 emissions from the calcium carbide process unit using 
the carbon mass balance procedure specified in paragraphs (b)(1) and 
(2) of this section.
    (1) For each calcium carbide process unit, determine the annual 
mass of carbon in each carbon-containing input and output material for 
the calcium carbide process unit and estimate annual process 
CO2 emissions from the calcium carbide process unit using 
equation 1 to this paragraph (b)(1). Carbon-containing input materials 
include carbon electrodes and carbonaceous reducing agents. If you 
document that a specific input or output material contributes less than 
1 percent of the total carbon into or out of the process, you do not 
have to include the material in your calculation using equation 1.
Equation 1 to paragraph (b)(1)
[GRAPHIC] [TIFF OMITTED] TR25AP24.071

Where:

ECO2 = Annual process CO2 emissions from an 
individual calcium carbide process unit (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Mreducing agenti = Annual mass of reducing agent i fed, 
charged, or otherwise introduced into the calcium carbide process 
unit (tons).
Creducing agenti = Carbon content in reducing agent i 
(percent by weight, expressed as a decimal fraction).
Melectrodem = Annual mass of carbon electrode m consumed 
in the calcium carbide process unit (tons).
Celectrodem = Carbon content of the carbon electrode m 
(percent by weight, expressed as a decimal fraction).
Mproduct outgoingk = Annual mass of alloy product k 
tapped from the calcium carbide process unit (tons).
Cproduct outgoingk = Carbon content in alloy product k 
(percent by weight, expressed as a decimal fraction).
Mnon-product outgoingl = Annual mass of non-product 
outgoing material l removed from the calcium carbide unit (tons).
Cnon-product outgoing = Carbon content in non-product 
outgoing material l (percent by weight, expressed as a decimal 
fraction).

    (2) Determine the combined annual process CO2 emissions 
from the calcium carbide process units at your facility using equation 
2 to this paragraph (b)(2).
Equation 2 to paragraph (b)(2)
CO2 = [Sigma]1^k ECO2k

Where:

CO2 = Annual process CO2 emissions from 
calcium carbide process units at a facility used for the production 
of calcium carbide (metric tons).
ECO2k = Annual process CO2 emissions 
calculated from calcium carbide process unit k calculated using 
equation 1 to paragraph (b)(1) of this section (metric tons).
k = Total number of calcium carbide process units at facility.

    (c) If all GHG emissions from a calcium carbide process unit are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part, then the calculation methodology in paragraph (b) of this section 
must not be used to calculate process emissions. The owner or operator 
must report under this subpart the combined stack emissions according 
to the Tier 4 Calculation Methodology in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part.


Sec.  98.504  Monitoring and QA/QC requirements.

    If you determine annual process CO2 emissions using the 
carbon mass balance procedure in Sec.  98.503(b), you must meet the 
requirements specified in paragraphs (a) and (b) of this section.
    (a) Determine the annual mass for each material used for the 
calculations of annual process CO2 emissions using equation 
1 to Sec.  98.503(b)(1) by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    (b) For each material identified in paragraph (a) of this section, 
you must determine the average carbon content of the material consumed, 
used, or produced in the calendar year using the methods specified in 
either paragraph (b)(1) or (2) of this section. If you document that a 
specific process input or output contributes less than one percent of 
the total mass of carbon into or out of the process, you do not have to 
determine the monthly mass or annual carbon content of that input or 
output.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material inputs and outputs each year. The carbon content of the 
material must be analyzed at least annually using the standard methods 
(and their QA/QC procedures) specified in paragraphs (b)(2)(i) and (ii) 
of this section, as applicable.
    (i) ASTM D5373-08 (incorporated by reference, see Sec.  98.7), for 
analysis of carbonaceous reducing agents and carbon electrodes.
    (ii) ASTM C25-06 (incorporated by reference, see Sec.  98.7) for 
analysis of materials such as limestone or dolomite.


Sec.  98.505   Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions

[[Page 31954]]

calculations in Sec.  98.503 is required. Therefore, whenever a 
quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter must be used in the 
calculations as specified in the paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) If you determine CO2 emissions for the calcium 
carbide process unit at your facility using the carbon mass balance 
procedure in Sec.  98.503(b), 100 percent data availability is required 
for the carbon content of the input and output materials. You must 
repeat the test for average carbon contents of inputs according to the 
procedures in Sec.  98.504(b) if data are missing.
    (b) For missing records of the monthly mass of carbon-containing 
inputs and outputs, the substitute data value must be based on the best 
available estimate of the mass of the inputs and outputs from all 
available process data or data used for accounting purposes, such as 
purchase records.


Sec.  98.506   Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (h) of this section, as applicable:
    (a) Annual facility calcium carbide production capacity (tons).
    (b) The annual facility production of calcium carbide (tons).
    (c) Total number of calcium carbide process units at facility used 
for production of calcium carbide.
    (d) Annual facility consumption of petroleum coke (tons).
    (e) Each end use of any calcium carbide produced and sent off site.
    (f) If the facility produces acetylene on site, provide the 
information in paragraphs (f)(1) through (3) of this section.
    (1) The annual production of acetylene at the facility (tons).
    (2) The annual quantity of calcium carbide used for the production 
of acetylene at the facility (tons).
    (3) Each end use of any acetylene produced on-site.
    (g) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec.  98.36 for the Tier 4 Calculation Methodology and the information 
specified in paragraphs (g)(1) and (2) of this section.
    (1) Annual CO2 emissions (in metric tons) from each CEMS 
monitoring location measuring process emissions from the calcium 
carbide process unit.
    (2) Identification number of each process unit.
    (h) If a CEMS is not used to measure CO2 process 
emissions, and the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec.  
98.503(b), then you must report the information specified in paragraphs 
(h)(1) through (3) of this section.
    (1) Annual process CO2 emissions (in metric tons) from 
each calcium carbide process unit.
    (2) List the method used for the determination of carbon content 
for each input and output material included in the calculation of 
annual process CO2 emissions for each calcium carbide 
process unit (i.e., supplier provided information, analyses of 
representative samples you collected).
    (3) If you use the missing data procedures in Sec.  98.505(b), you 
must report for each calcium carbide production process unit how 
monthly mass of carbon-containing inputs and outputs with missing data 
were determined and the number of months the missing data procedures 
were used.


Sec.  98.507  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section for each calcium carbide process unit, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according to the 
requirements in Sec.  98.503(a), then you must retain under this 
subpart the records required for the Tier 4 Calculation Methodology in 
Sec.  98.37 and the information specified in paragraphs (a)(1) through 
(3) of this section.
    (1) Monthly calcium carbide process unit production quantity 
(tons).
    (2) Number of calcium carbide processing unit operating hours each 
month.
    (3) Number of calcium carbide processing unit operating hours in a 
calendar year.
    (b) If the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec.  
98.503(b)(2), then you must retain records for the information 
specified in paragraphs (b)(1) through (5) of this section.
    (1) Monthly calcium carbide process unit production quantity 
(tons).
    (2) Number of calcium carbide process unit operating hours each 
month.
    (3) Number of calcium carbide process unit operating hours in a 
calendar year.
    (4) Monthly material quantity consumed, used, or produced for each 
material included for the calculations of annual process CO2 
emissions (tons).
    (5) Average carbon content determined and records of the supplier 
provided information or analyses used for the determination for each 
material included for the calculations of annual process CO2 
emissions.
    (c) You must keep records that include a detailed explanation of 
how company records of measurements are used to estimate the carbon 
input and output to each calcium carbide process unit, including 
documentation of specific input or output materials excluded from 
equation 1 to Sec.  98.503(b)(1) that contribute less than 1 percent of 
the total carbon into or out of the process. You also must document the 
procedures used to ensure the accuracy of the measurements of materials 
fed, charged, or placed in a calcium carbide process unit including, 
but not limited to, calibration of weighing equipment and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.
    (d) The applicable verification software records as identified in 
this paragraph (d). You must keep a record of the file generated by the 
verification software specified in Sec.  98.5(b) for the applicable 
data specified in paragraphs (d)(1) through (8) of this section. 
Retention of this file satisfies the recordkeeping requirement for the 
data in paragraphs (d)(1) through (8) of this section.
    (1) Carbon content in reducing agent (percent by weight, expressed 
as a decimal fraction) (equation 1 to Sec.  98.503(b)(1)).
    (2) Annual mass of reducing agent fed, charged, or otherwise 
introduced into the calcium carbide process unit (tons) (equation 1 to 
Sec.  98.503(b)(1)).
    (3) Carbon content of carbon electrode (percent by weight, 
expressed as a decimal fraction) (equation 1 to Sec.  98.503(b)(1)).
    (4) Annual mass of carbon electrode consumed in the calcium carbide 
process unit (tons) (equation 1 to Sec.  98.503(b)(1)).
    (5) Carbon content in product (percent by weight, expressed as a 
decimal fraction) (equation 1 to Sec.  98.503(b)(1)).
    (6) Annual mass of product produced/tapped in the calcium carbide 
process unit (tons) (equation 1 to Sec.  98.503(b)(1)).
    (7) Carbon content in non-product outgoing material (percent by 
weight, expressed as a decimal fraction) (equation 1 to Sec.  
98.503(b)(1)).
    (8) Annual mass of non-product outgoing material removed from 
calcium carbide process unit (tons) (equation 1 to Sec.  98.503(b)(1)).

[[Page 31955]]

Sec.  98.508  Definitions.

    All terms used of this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid Production

Sec.
98.510 Definition of the source category.
98.511 Reporting threshold.
98.512 GHGs to report.
98.513 Calculating GHG emissions.
98.514 Monitoring and QA/QC requirements.
98.515 Procedures for estimating missing data.
98.516 Data reporting requirements.
98.517 Records that must be retained.
98.518 Definitions.
Table 1 to Subpart YY of Part 98--N2O Generation Factors


Sec.  98.510  Definition of the source category.

    This source category includes any facility that produces 
caprolactam, glyoxal, or glyoxylic acid. This source category excludes 
the production of glyoxal through the LaPorte process (i.e., the gas-
phase catalytic oxidation of ethylene glycol with air in the presence 
of a silver or copper catalyst).


Sec.  98.511  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
meets the requirements of either Sec.  98.2(a)(1) or (2) and the 
definition of source category in Sec.  98.510.


Sec.  98.512  GHGs to report.

    (a) You must report N2O process emissions from the 
production of caprolactam, glyoxal, and glyoxylic acid as required by 
this subpart.
    (b) You must report under subpart C of this part the emissions of 
CO2, CH4, and N2O from each stationary 
combustion unit by following the requirements of subpart C of this 
part.


Sec.  98.513   Calculating GHG emissions.

    (a) You must determine annual N2O process emissions from 
each caprolactam, glyoxal, and glyoxylic acid process line using the 
appropriate default N2O generation factor(s) from table 1 to 
this subpart, the site-specific N2O destruction factor(s) 
for each N2O abatement device, and site-specific production 
data according to paragraphs (b) through (e) of this section.
    (b) You must determine the total annual amount of product i 
(caprolactam, glyoxal, or glyoxylic acid) produced on each process line 
t (metric tons product), according to Sec.  98.514(b).
    (c) If process line t exhausts to any N2O abatement 
technology j, you must determine the destruction efficiency for each 
N2O abatement technology according to paragraph (c)(1) or 
(2) of this section.
    (1) Use the control device manufacturer's specified destruction 
efficiency.
    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
(if applicable) was used to determine the destruction efficiency.
    (d) If process line t exhausts to any N2O abatement 
technology j, you must determine the abatement utilization factor for 
each N2O abatement technology according to paragraph (d)(1) 
or (2) of this section.
    (1) If the abatement technology j has no downtime during the year, 
use 1.
    (2) If the abatement technology j was not operational while product 
i was being produced on process line t, calculate the abatement 
utilization factor according to equation 1 to this paragraph (d)(2).
Equation 1 to paragraph (d)(2)
[GRAPHIC] [TIFF OMITTED] TR25AP24.072

Where:

AFj = Monthly abatement utilization factor of 
N2O abatement technology j from process unit t (fraction 
of time that abatement technology is operating).
Ti,j = Total number of hours during month that product i 
(caprolactam, glyoxal, or glyoxylic acid), was produced from process 
unit t during which N2O abatement technology j was 
operational (hours).
Ti = Total number of hours during month that product i 
(caprolactam, glyoxal, or glyoxylic acid), was produced from process 
unit t (hours).

    (e) You must calculate N2O emissions for each product i 
from each process line t and each N2O control technology j 
according to equation 2 to this paragraph (e).
Equation 2 to paragraph (e)
[GRAPHIC] [TIFF OMITTED] TR25AP24.073

Where:

EN2Ot = Monthly process emissions of N2O, 
metric tons from process line t.
EFi = N2O generation factor for product i 
(caprolactam, glyoxal, or glyoxylic acid), kg N2O/metric 
ton of product produced, as shown in table 1 to this subpart.
Pi = Monthly production of product i, (caprolactam, 
glyoxal, or glyoxylic acid), metric tons.
DEj = Destruction efficiency of N2O abatement 
technology type j, fraction (decimal fraction of N2O 
removed from vent stream).
AFj = Monthly abatement utilization factor for 
N2O abatement technology type j, fraction, calculated 
using equation 1 to paragraph (d)(2) of this section.
0.001 = Conversion factor from kg to metric tons.

    (f) You must determine the annual emissions combined from each 
process line at your facility using equation 3 to this paragraph (f):
Equation 3 to paragraph (f)
[GRAPHIC] [TIFF OMITTED] TR25AP24.074


[[Page 31956]]


Where:

N2O = Annual process N2O emissions from each 
process line for product i (caprolactam, glyoxal, or glyoxylic acid) 
(metric tons).
EN2Ot = Monthly process emissions of N2O from 
each process line for product i (caprolactam, glyoxal, or glyoxylic 
acid) (metric tons).


Sec.  98.514   Monitoring and QA/QC requirements.

    (a) You must determine the total monthly amount of caprolactam, 
glyoxal, and glyoxylic acid produced. These monthly amounts are 
determined according to the methods in paragraph (a)(1) or (2) of this 
section.
    (1) Direct measurement of production (such as using flow meters, 
weigh scales, etc.).
    (2) Existing plant procedures used for accounting purposes (i.e., 
dedicated tank-level and acid concentration measurements).
    (b) You must determine the annual amount of caprolactam, glyoxal, 
and glyoxylic acid produced. These annual amounts are determined by 
summing the respective monthly quantities determined in paragraph (a) 
of this section.


Sec.  98.515   Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter must be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of caprolactam, glyoxal, or glyoxylic 
acid production, the substitute data must be the best available 
estimate based on all available process data or data used for 
accounting purposes (such as sales records).
    (b) For missing values related to the N2O abatement 
device, assuming that the operation is generally constant from year to 
year, the substitute data value should be the most recent quality-
assured value.


Sec.  98.516  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (j) of this section.
    (a) Process line identification number.
    (b) Annual process N2O emissions from each process line 
according to paragraphs (b)(1) through (3) of this section.
    (1) N2O from caprolactam production (metric tons).
    (2) N2O from glyoxal production (metric tons).
    (3) N2O from glyoxylic acid production (metric tons).
    (c) Annual production quantities from all process lines at the 
caprolactam, glyoxal, or glyoxylic acid production facility according 
to paragraphs (c)(1) through (3) of this section.
    (1) Caprolactam production (metric tons).
    (2) Glyoxal production (metric tons).
    (3) Glyoxylic acid production (metric tons).
    (d) Annual production capacity from all process lines at the 
caprolactam, glyoxal, or glyoxylic acid production facility, as 
applicable, in paragraphs (d)(1) through (3) of this section.
    (1) Caprolactam production capacity (metric tons).
    (2) Glyoxal production capacity (metric tons).
    (3) Glyoxylic acid production capacity (metric tons).
    (e) Number of process lines at the caprolactam, glyoxal, or 
glyoxylic acid production facility, by product, in paragraphs (e)(1) 
through (3) of this section.
    (1) Total number of process lines producing caprolactam.
    (2) Total number of process lines producing glyoxal.
    (3) Total number of process lines producing glyoxylic acid.
    (f) Number of operating hours in the calendar year for each process 
line at the caprolactam, glyoxal, or glyoxylic acid production facility 
(hours).
    (g) N2O abatement technologies used (if applicable) and 
date of installation of abatement technology at the caprolactam, 
glyoxal, or glyoxylic acid production facility.
    (h) Monthly abatement utilization factor for each N2O 
abatement technology for each process line at the caprolactam, glyoxal, 
or glyoxylic acid production facility.
    (i) Number of times in the reporting year that missing data 
procedures were followed to measure production quantities of 
caprolactam, glyoxal, or glyoxylic acid (months).
    (j) Annual percent N2O emission reduction per chemical 
produced at the caprolactam, glyoxal, or glyoxylic acid production 
facility, as applicable, in paragraphs (j)(1) through (3) of this 
section.
    (1) Annual percent N2O emission reduction for all 
caprolactam production process lines.
    (2) Annual percent N2O emission reduction for all 
glyoxal production process lines.
    (3) Annual percent N2O emission reduction for all 
glyoxylic acid production process lines.


Sec.  98.517   Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section for each caprolactam, glyoxal, or glyoxylic acid production 
facility:
    (a) Documentation of how accounting procedures were used to 
estimate production rate.
    (b) Documentation of how process knowledge was used to estimate 
abatement technology destruction efficiency (if applicable).
    (c) Documentation of the procedures used to ensure the accuracy of 
the measurements of all reported parameters, including but not limited 
to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.
    (d) The applicable verification software records as identified in 
this paragraph (d). You must keep a record of the file generated by the 
verification software specified in Sec.  98.5(b) for the applicable 
data specified in paragraphs (d)(1) through (4) of this section. 
Retention of this file satisfies the recordkeeping requirement for the 
data in paragraphs (d)(1) through (4) of this section.
    (1) Monthly production quantity of caprolactam from each process 
line at the caprolactam, glyoxal, or glyoxylic acid production facility 
(metric tons).
    (2) Monthly production quantity of glyoxal from each process line 
at the caprolactam, glyoxal, or glyoxylic acid production facility 
(metric tons).
    (3) Monthly production quantity of glyoxylic acid from each process 
line at the caprolactam, glyoxal, or glyoxylic acid production facility 
(metric tons).
    (4) Destruction efficiency of N2O abatement technology 
from each process line, fraction (decimal fraction of N2O 
removed from vent stream).


Sec.  98.518   Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

        Table 1 to Subpart YY of Part 98--N2O Generation Factors
------------------------------------------------------------------------
                                                                 N2O
                          Product                             generation
                                                              factor \a\
------------------------------------------------------------------------
Caprolactam................................................          9.0
Glyoxal....................................................          520

[[Page 31957]]

 
Glyoxylic acid.............................................          100
------------------------------------------------------------------------
\a\ Generation factors in units of kilograms of N2O emitted per metric
  ton of product produced.

Subpart ZZ--Ceramics Manufacturing

Sec.
98.520 Definition of the source category.
98.521 Reporting threshold.
98.522 GHGs to report.
98.523 Calculating GHG emissions.
98.524 Monitoring and QA/QC requirements.
98.525 Procedures for estimating missing data.
98.526 Data reporting requirements.
98.527 Records that must be retained.
98.528 Definitions.
Table 1 to Subpart ZZ of Part 98--CO2 Emission Factors 
for Carbonate-Based Raw Materials


Sec.  98.520   Definition of the source category.

    (a) The ceramics manufacturing source category consists of any 
facility that uses nonmetallic, inorganic materials, many of which are 
clay-based, to produce ceramic products such as bricks and roof tiles, 
wall and floor tiles, table and ornamental ware (household ceramics), 
sanitary ware, refractory products, vitrified clay pipes, expanded clay 
products, inorganic bonded abrasives, and technical ceramics (e.g., 
aerospace, automotive, electronic, or biomedical applications). For the 
purposes of this subpart, ceramics manufacturing processes include 
facilities that annually consume at least 2,000 tons of carbonates, 
either as raw materials or as a constituent in clay, which is heated to 
a temperature sufficient to allow the calcination reaction to occur, 
and operate a ceramics manufacturing process unit.
    (b) A ceramics manufacturing process unit is a kiln, dryer, or oven 
used to calcine clay or other carbonate-based materials for the 
production of a ceramics product.


Sec.  98.521  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a ceramics manufacturing process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.522   GHGs to report.

    You must report:
    (a) CO2 process emissions from each ceramics process 
unit (e.g., kiln, dryer, or oven).
    (b) CO2 combustion emissions from each ceramics process 
unit.
    (c) CH4 and N2O combustion emissions from 
each ceramics process unit. You must calculate and report these 
emissions under subpart C of this part by following the requirements of 
subpart C of this part.
    (d) CO2, CH4, and N2O combustion 
emissions from each stationary fuel combustion unit other than kilns, 
dryers, or ovens. You must report these emissions under subpart C of 
this part by following the requirements of subpart C of this part.


Sec.  98.523  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each ceramics process unit using the procedures in 
paragraphs (a) through (c) of this section.
    (a) For each ceramics process unit that meets the conditions 
specified in Sec.  98.33(b)(4)(ii) or (iii), you must calculate and 
report under this subpart the combined process and combustion 
CO2 emissions by operating and maintaining a CEMS to measure 
CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.
    (b) For each ceramics process unit that is not subject to the 
requirements in paragraph (a) of this section, calculate and report the 
process and combustion CO2 emissions from the ceramics 
process unit separately by using the procedures specified in paragraphs 
(b)(1) through (6) of this section, except as specified in paragraph 
(c) of this section.
    (1) For each carbonate-based raw material (including clay) charged 
to the ceramics process unit, either obtain the mass fractions of any 
carbonate-based minerals from the supplier of the raw material or by 
sampling the raw material, or use a default value of 1.0 as the mass 
fraction for the raw material.
    (2) Determine the quantity of each carbonate-based raw material 
charged to the ceramics process unit.
    (3) Apply the appropriate emission factor for each carbonate-based 
raw material charged to the ceramics process unit. Table 1 to this 
subpart provides emission factors based on stoichiometric ratios for 
carbonate-based minerals.
    (4) Use equation 1 to this paragraph (b)(4) to calculate process 
mass emissions of CO2 for each ceramics process unit:
Equation 1 to paragraph (b)(4)
[GRAPHIC] [TIFF OMITTED] TR25AP24.075

Where:

ECO2 = Annual process CO2 emissions (metric 
tons/year).
Mj = Annual mass of the carbonate-based raw material j 
consumed (tons/year).
2000/2205 = Conversion factor to convert tons to metric tons.
MFi = Annual average decimal mass fraction of carbonate-
based mineral i in carbonate-based raw material j.
EFi = Emission factor for the carbonate-based mineral i, 
(metric tons CO2/metric ton carbonate, see table 1 to 
this subpart).
Fi = Decimal fraction of calcination achieved for 
carbonate-based mineral i, assumed to be equal to 1.0.
i = Index for carbonate-based mineral in each carbonate-based raw 
material.
j = Index for carbonate-based raw material.

    (5) Determine the combined annual process CO2 emissions 
from the ceramic process units at your facility using equation 2 to 
this paragraph (b)(5):
Equation 2 to paragraph (b)(5)
CO2 = [Sigma]^k1 ECO2k

Where:

CO2 = Annual process CO2 emissions from 
ceramic process units at a facility (metric tons).
ECO2k = Annual process CO2 emissions 
calculated from ceramic process unit k calculated using equation 1 
to paragraph (b)(4) of this section (metric tons).
k = Total number of ceramic process units at facility.

    (6) Calculate and report under subpart C of this part the 
combustion CO2 emissions in the ceramics process unit 
according to the applicable requirements in subpart C of this part.
    (c) A value of 1.0 can be used for the mass fraction 
(MFi) of carbonate-based mineral i in each carbonate-based 
raw material j in equation 1 to paragraph (b)(4) of this section. The 
use of 1.0 for the mass fraction assumes that the carbonate-based raw 
material comprises 100% of one carbonate-based mineral. As an 
alternative to the default value, you may use data provided by either 
the raw material supplier or a lab analysis.

[[Page 31958]]

Sec.  98.524   Monitoring and QA/QC requirements.

    (a) You must measure annual amounts of carbonate-based raw 
materials charged to each ceramics process unit from monthly 
measurements using plant instruments used for accounting purposes, such 
as calibrated scales or weigh hoppers. Total annual mass charged to 
ceramics process units at the facility must be compared to records of 
raw material purchases for the year.
    (b) You must use the default value of 1.0 for the mass fraction of 
a carbonate-based mineral, or you may opt to obtain the mass fraction 
of any carbonate-based materials from the supplier of the raw material 
or by sampling the raw material. If you opt to obtain the mass 
fractions of any carbonate-based minerals from the supplier of the raw 
material or by sampling the raw material, you must measure the 
carbonate-based mineral mass fractions at least annually to verify the 
mass fraction data. You may conduct the sampling and chemical analysis 
using any x-ray fluorescence test, x-ray diffraction test, or other 
enhanced testing method published by an industry consensus standards 
organization (e.g., ASTM, ASME, API). If it is determined that the mass 
fraction of a carbonate based raw material is below the detection limit 
of available industry testing standards, you may use a default value of 
0.005.
    (c) You must use the default value of 1.0 for the mass fraction of 
a carbonate-based mineral, or you may opt to obtain the mass fraction 
of any carbonate-based materials from the supplier of the raw material 
or by sampling the raw material. If you obtain the mass fractions of 
any carbonate-based minerals from the supplier of the raw material or 
by sampling the raw material, you must determine the annual average 
mass fraction for the carbonate-based mineral in each carbonate-based 
raw material at least annually by calculating an arithmetic average of 
the data obtained from raw material suppliers or sampling and chemical 
analysis.
    (d) You must use the default value of 1.0 for the calcination 
fraction of a carbonate-based mineral. Alternatively, you may opt to 
obtain the calcination fraction of any carbonate-based mineral by 
sampling. If you opt to obtain the calcination fraction of any 
carbonate-based minerals from sampling, you must determine on an annual 
basis the calcination fraction for each carbonate-based mineral 
consumed based on sampling and chemical analysis. You may conduct the 
sampling and chemical analysis using any x-ray fluorescence test, x-ray 
diffraction test, or other enhanced testing method published by an 
industry consensus standards organization (e.g., ASTM, ASME, API).


Sec.  98.525   Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.523 is required. If the monitoring 
and quality assurance procedures in Sec.  98.524 cannot be followed and 
data is unavailable, you must use the most appropriate of the missing 
data procedures in paragraphs (a) and (b) of this section in the 
calculations. You must document and keep records of the procedures used 
for all such missing value estimates.
    (a) If the CEMS approach is used to determine combined process and 
combustion CO2 emissions, the missing data procedures in 
Sec.  98.35 apply.
    (b) For missing data on the monthly amounts of carbonate-based raw 
materials charged to any ceramics process unit, use the best available 
estimate(s) of the parameter(s) based on all available process data or 
data used for accounting purposes, such as purchase records.
    (c) For missing data on the mass fractions of carbonate-based 
minerals in the carbonate-based raw materials, assume that the mass 
fraction of a carbonate-based mineral is 1.0, which assumes that one 
carbonate-based mineral comprises 100 percent of the carbonate-based 
raw material.


Sec.  98.526   Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (c) of this section, as applicable:
    (a) The total number of ceramics process units at the facility and 
the number of units that operated during the reporting year.
    (b) If a CEMS is used to measure CO2 emissions from 
ceramics process units, then you must report under this subpart the 
relevant information required under Sec.  98.36 for the Tier 4 
Calculation Methodology and the following information specified in 
paragraphs (b)(1) through (3) of this section.
    (1) The annual quantity of each carbonate-based raw material 
(including clay) charged to each ceramics process unit and for all 
units combined (tons).
    (2) Annual quantity of each type of ceramics product manufactured 
by each ceramics process unit and by all units combined (tons).
    (3) Annual production capacity for each ceramics process unit 
(tons).
    (c) If a CEMS is not used to measure CO2 emissions from 
ceramics process units and process CO2 emissions are 
calculated according to the procedures specified in Sec.  98.523(b), 
then you must report the following information specified in paragraphs 
(c)(1) through (7) of this section.
    (1) Annual process emissions of CO2 (metric tons) for 
each ceramics process unit and for all units combined.
    (2) The annual quantity of each carbonate-based raw material 
(including clay) charged to each ceramics process unit and for all 
units combined (tons).
    (3) Results of all tests used to verify each carbonate-based 
mineral mass fraction for each carbonate-based raw material charged to 
a ceramics process unit, as specified in paragraphs (c)(3)(i) through 
(iii) of this section.
    (i) Date of test.
    (ii) Method(s) and any variations used in the analyses.
    (iii) Mass fraction of each sample analyzed.
    (4) Method used to determine the decimal mass fraction of 
carbonate-based mineral, unless you used the default value of 1.0 
(e.g., supplier provided information, analyses of representative 
samples you collected, or use of a default value of 0.005 as specified 
by Sec.  98.524(b)).
    (5) Annual quantity of each type of ceramics product manufactured 
by each ceramics process unit and by all units combined (tons).
    (6) Annual production capacity for each ceramics process unit 
(tons).
    (7) If you use the missing data procedures in Sec.  98.525(b), you 
must report for each applicable ceramics process unit the number of 
times in the reporting year that missing data procedures were followed 
to measure monthly quantities of carbonate-based raw materials or mass 
fraction of the carbonate-based minerals (months).


Sec.  98.527   Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section for each ceramics process unit, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according 
to the requirements in Sec.  98.523(a), then you must retain under this 
subpart the records required under Sec.  98.37 for the Tier 4 
Calculation Methodology and the information specified in paragraphs 
(a)(1) and (2) of this section.
    (1) Monthly ceramics production rate for each ceramics process unit 
(tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each ceramics process unit (tons).
    (b) If process CO2 emissions are calculated according to 
the procedures

[[Page 31959]]

specified in Sec.  98.523(b), you must retain the records in paragraphs 
(b)(1) through (6) of this section.
    (1) Monthly ceramics production rate for each ceramics process unit 
(metric tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each ceramics process unit (metric tons).
    (3) Data on carbonate-based mineral mass fractions provided by the 
raw material supplier for all raw materials consumed annually and 
included in calculating process emissions in equation 1 to Sec.  
98.523(b)(4), if applicable.
    (4) Results of all tests, if applicable, used to verify the 
carbonate-based mineral mass fraction for each carbonate-based raw 
material charged to a ceramics process unit, including the data 
specified in paragraphs (b)(4)(i) through (v) of this section.
    (i) Date of test.
    (ii) Method(s), and any variations of methods, used in the 
analyses.
    (iii) Mass fraction of each sample analyzed.
    (iv) Relevant calibration data for the instrument(s) used in the 
analyses.
    (v) Name and address of laboratory that conducted the tests.
    (5) Each carbonate-based mineral mass fraction for each carbonate-
based raw material, if a value other than 1.0 is used to calculate 
process mass emissions of CO2.
    (6) Number of annual operating hours of each ceramics process unit.
    (c) All other documentation used to support the reported GHG 
emissions.
    (d) The applicable verification software records as identified in 
this paragraph (d). You must keep a record of the file generated by the 
verification software specified in Sec.  98.5(b) for the applicable 
data specified in paragraphs (d)(1) through (3) of this section. 
Retention of this file satisfies the recordkeeping requirement for the 
data in paragraphs (d)(1) through (3) of this section.
    (1) Annual average decimal mass fraction of each carbonate-based 
mineral in each carbonate-based raw material for each ceramics process 
unit (specify the default value, if used, or the value determined 
according to Sec.  98.524) (percent by weight, expressed as a decimal 
fraction) (equation 1 to Sec.  98.523(b)(4)).
    (2) Annual mass of each carbonate-based raw material charged to 
each ceramics process unit (tons) (equation 1 to Sec.  98.523(b)(4)).
    (3) Decimal fraction of calcination achieved for each carbonate-
based raw material for each ceramics process unit (specify the default 
value, if used, or the value determined according to Sec.  98.524) 
(percent by weight, expressed as a decimal fraction) (equation 1 to 
Sec.  98.523(b)(4)).


Sec.  98.528  Definitions.

    All terms used of this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

  Table 1 to Subpart ZZ of Part 98--CO2 Emission Factors for Carbonate-
                           Based Raw Materials
------------------------------------------------------------------------
                                                           CO2 emission
           Carbonate                 Mineral name(s)        factor \a\
 
------------------------------------------------------------------------
BaCO3..........................  Witherite, Barium                 0.223
                                  carbonate.
CaCO3..........................  Limestone, Calcium                0.440
                                  Carbonate, Calcite,
                                  Aragonite.
Ca(Fe,Mg,Mn)(CO3)2.............  Ankerite \b\...........     0.408-0.476
CaMg(CO3)2.....................  Dolomite...............           0.477
FeCO3..........................  Siderite...............           0.380
K2CO3..........................  Potassium carbonate....           0.318
Li2CO3.........................  Lithium carbonate......           0.596
MgCO3..........................  Magnesite..............           0.522
MnCO3..........................  Rhodochrosite..........           0.383
Na2CO3.........................  Sodium carbonate, Soda            0.415
                                  ash.
SrCO3..........................  Strontium carbonate,              0.298
                                  Strontianite.
------------------------------------------------------------------------
\a\ Emission factors are in units of metric tons of CO2 emitted per
  metric ton of carbonate-based material.
\b\ Ankerite emission factors are based on a formula weight range that
  assumes Fe, Mg, and Mn are present in amounts of at least 1.0 percent.

 [FR Doc. 2024-07413 Filed 4-24-24; 8:45 am]
 BILLING CODE 6560-50-P

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