section_id,title_number,title_name,chapter,subchapter,part_number,part_name,subpart,subpart_name,section_number,section_heading,agency,authority,source_citation,amendment_citations,full_text 34:34:1.1.1.1.31.0.113.1,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.1 Applicability of part.,ED,,,,"This part applies to any program administered by the Secretary of Education that: (a)(1) Was transferred to the Department by the Department of Education Organization Act (DEOA); and (2) Was administered by the Education Division of the Department of Health, Education, and Welfare on the day before the effective date of the DEOA; or (b) Was enacted after the effective date of the DEOA, unless the law enacting the new Federal program has the effect of making section 439 of the General Education Provisions Act inapplicable. (c) The following chart lists the funded programs to which part 98 does not apply as of February 16, 1984." 34:34:1.1.1.1.31.0.113.10,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.10 Enforcement of the findings.,ED,,,,"(a) If the recipient or contractor does not comply during the period of time set under § 98.9(c), the Secretary may either: (1) For a recipient, take an action authorized under 34 CFR part 78, including: (i) Issuing a notice of intent to terminate funds under 34 CFR 78.21; (ii) Issuing a notice to withhold funds under 34 CFR 78.21, 200.94(b), or 298.45(b), depending upon the applicable program under which the notice is issued; or (iii) Issuing a notice to cease and desist under 34 CFR 78.31, 200.94(c) or 298.45(c), depending upon the program under which the notice is issued; or (2) For a contractor, direct the contracting officer to take an appropriate action authorized under the Federal Acquisition Regulations, including either: (i) Issuing a notice to suspend operations under 48 CFR 12.5; or (ii) Issuing a notice to terminate for default, either in whole or in part under 48 CFR 49.102. (b) If, after an investigation under § 98.9, the Secretary finds that a recipient or contractor has complied voluntarily with section 439 of the Act, the Secretary provides the complainant and the recipient or contractor written notice of the decision and the basis for the decision." 34:34:1.1.1.1.31.0.113.2,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.2 Definitions.,ED,,,,"(a) The following terms used in this part are defined in 34 CFR part 77; “Department,” “Recipient,” “Secretary.” (b) The following definitions apply to this part: Act means the General Education Provisions Act. Office means the information and investigation office specified in § 98.5." 34:34:1.1.1.1.31.0.113.3,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.3 Access to instructional material used in a research or experimentation program.,ED,,,,"(a) All instructional material—including teachers' manuals, films, tapes, or other supplementary instructional material—which will be used in connection with any research or experimentation program or project shall be available for inspection by the parents or guardians of the children engaged in such program or project. (b) For the purpose of this part research or experimentation program or project means any program or project in any program under § 98.1 (a) or (b) that is designed to explore or develop new or unproven teaching methods or techniques. (c) For the purpose of the section children means persons not above age 21 who are enrolled in a program under § 98.1 (a) or (b) not above the elementary or secondary education level, as determined under State law." 34:34:1.1.1.1.31.0.113.4,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,"§ 98.4 Protection of students' privacy in examination, testing, or treatment.",ED,,,,"(a) No student shall be required, as part of any program specified in § 98.1 (a) or (b), to submit without prior consent to psychiatric examination, testing, or treatment, or psychological examination, testing, or treatment, in which the primary purpose is to reveal information concerning one or more of the following: (1) Political affiliations; (2) Mental and psychological problems potentially embarrassing to the student or his or her family; (3) Sex behavior and attitudes; (4) Illegal, anti-social, self-incriminating and demeaning behavior; (5) Critical appraisals of other individuals with whom the student has close family relationships; (6) Legally recognized privileged and analogous relationships, such as those of lawyers, physicians, and ministers; or (7) Income, other than that required by law to determine eligibility for participation in a program or for receiving financial assistance under a program. (b) As used in paragraph (a) of this section, prior consent means: (1) Prior consent of the student, if the student is an adult or emancipated minor; or (2) Prior written consent of the parent or guardian, if the student is an unemancipated minor. (c) As used in paragraph (a) of this section: (1) Psychiatric or psychological examination or test means a method of obtaining information, including a group activity, that is not directly related to academic instruction and that is designed to elicit information about attitudes, habits, traits, opinions, beliefs or feelings; and (2) Psychiatric or psychological treatment means an activity involving the planned, systematic use of methods or techniques that are not directly related to academic instruction and that is designed to affect behavioral, emotional, or attitudinal characteristics of an individual or group." 34:34:1.1.1.1.31.0.113.5,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.5 Information and investigation office.,ED,,,,"(a) The Secretary has designated an office to provide information about the requirements of section 439 of the Act, and to investigate, process, and review complaints that may be filed concerning alleged violations of the provisions of the section. (b) The following is the name and address of the office designated under paragraph (a) of this section: Family Educational Rights and Privacy Act Office, U.S. Department of Education, 400 Maryland Avenue, SW., Washington, DC 20202." 34:34:1.1.1.1.31.0.113.6,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.6 Reports.,ED,,,,The Secretary may require the recipient to submit reports containing information necessary to resolve complaints under section 439 of the Act and the regulations in this part. 34:34:1.1.1.1.31.0.113.7,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.7 Filing a complaint.,ED,,,,"(a) Only a student or a parent or guardian of a student directly affected by a violation under Section 439 of the Act may file a complaint under this part. The complaint must be submitted in writing to the Office. (b) The complaint filed under paragraph (a) of this section must— (1) Contain specific allegations of fact giving reasonable cause to believe that a violation of either § 98.3 or § 98.4 exists; and (2) Include evidence of attempted resolution of the complaint at the local level (and at the State level if a State complaint resolution process exists), including the names of local and State officials contacted and significant dates in the attempted resolution process. (c) The Office investigates each complaint which the Office receives that meets the requirements of this section to determine whether the recipient or contractor failed to comply with the provisions of section 439 of the Act." 34:34:1.1.1.1.31.0.113.8,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.8 Notice of the complaint.,ED,,,,"(a) If the Office receives a complaint that meets the requirements of § 98.7, it provides written notification to the complainant and the recipient or contractor against which the violation has been alleged that the complaint has been received. (b) The notice to the recipient or contractor under paragraph (a) of this section must: (1) Include the substance of the alleged violation; and (2) Inform the recipient or contractor that the Office will investigate the complaint and that the recipient or contractor may submit a written response to the complaint." 34:34:1.1.1.1.31.0.113.9,34,Education,,,98,"PART 98—STUDENT RIGHTS IN RESEARCH, EXPERIMENTAL PROGRAMS, AND TESTING",,,,§ 98.9 Investigation and findings.,ED,,,,"(a) The Office may permit the parties to submit further written or oral arguments or information. (b) Following its investigations, the Office provides to the complainant and recipient or contractor written notice of its findings and the basis for its findings. (c) If the Office finds that the recipient or contractor has not complied with section 439 of the Act, the Office includes in its notice under paragraph (b) of this section: (1) A statement of the specific steps that the Secretary recommends the recipient or contractor take to comply; and (2) Provides a reasonable period of time, given all of the circumstances of the case, during which the recipient or contractor may comply voluntarily." 40:40:23.0.1.1.2.1.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.1 Purpose and scope.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 76 FR 73898, Nov. 29, 2011; 76 FR 80573, Dec. 23, 2011; 89 FR 42218, May 14, 2024]","(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied. (b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of this subpart and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the applicable subpart shall take precedence. (c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms Owner and Operator used in this subpart have the same definition as Onshore petroleum and natural gas production owner or operator, as defined in § 98.238. For facilities required to report under onshore petroleum and natural gas gathering and boosting under subpart W of this part, the terms Owner and Operator used in this subpart have the same definition as Gathering and boosting system owner or operator, as defined in § 98.238. For facilities required to report under onshore natural gas transmission pipeline under subpart W of this part, the terms Owner and Operator used in this subpart have the same definition as Onshore natural gas transmission pipeline owner or operator, as defined in § 98.238." 40:40:23.0.1.1.2.1.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.2 Who must report?,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 75 FR 57685, Sept. 22, 2010; 76 FR 73899, Nov. 29, 2011; 75 FR 74487, Nov. 30, 2010; 79 FR 73776, Dec. 11, 2014; 81 FR 89248, Dec. 9, 2016; 89 FR 31889, Apr. 25, 2024; 89 FR 42218, May 14, 2024]","(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section: (1) A facility that contains any source category that is listed in Table A-3 of this subpart. For these facilities, the annual GHG report must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all applicable source categories listed in Tables A-3 and A-4 of this subpart. (2) A facility that contains any source category that is listed in Table A-4 of this subpart and that emits 25,000 metric tons CO 2 e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all applicable source categories that are listed in Table A-3 and Table A-4 of this subpart. For these facilities, the annual GHG report must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all applicable source categories listed in Table A-3 and Table A-4 of this subpart. (3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only. (i) The facility does not meet the requirements of either paragraph (a)(1) or (a)(2) of this section. (ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater. (iii) The facility emits 25,000 metric tons CO 2 e or more per year in combined emissions from all stationary fuel combustion sources. (4) A supplier that is listed in Table A-5 of this subpart. For these suppliers, the annual GHG report must cover all applicable products for which calculation methodologies are provided in the subparts listed in Table A-5 of this subpart. (5) Research and development activities are not considered to be part of any source category defined in this part. (b) To calculate GHG emissions for comparison to the 25,000 metric ton CO 2 e per year emission threshold in paragraph (a)(2) of this section, the owner or operator shall calculate annual CO 2 e emissions, as described in paragraphs (b)(1) through (b)(4) of this section. (1) Calculate the annual emissions of CO 2 , CH 4 , N 2 O, and each fluorinated GHG in metric tons from all applicable source categories listed in paragraph (a)(2) of this section. The GHG emissions shall be calculated using the calculation methodologies specified in each applicable subpart and available company records. (2) For each general stationary fuel combustion unit, calculate the annual CO 2 emissions in metric tons using any of the four calculation methodologies specified in § 98.33(a). Calculate the annual CH 4 and N 2 O emissions from the stationary fuel combustion sources in metric tons using the appropriate equation in § 98.33(c). Exclude carbon dioxide emissions from the combustion of biomass, but include emissions of CH 4 and N 2 O from biomass combustion. (3) For miscellaneous uses of carbonate, calculate the annual CO 2 emissions in metric tons using the procedures specified in subpart U of this part. (4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and (b)(3) of this section for each GHG and calculate metric tons of CO 2 e using Equation A-1 of this section. Where: CO 2 e = Carbon dioxide equivalent, metric tons/year. GHG i = Mass emissions of each greenhouse gas, metric tons/year. GWP i = Global warming potential for each greenhouse gas from Table A-1 of this subpart. n = The number of greenhouse gases emitted. Where: CO 2 e = Carbon dioxide equivalent, metric tons/year. GHG i = Mass emissions of each greenhouse gas, metric tons/year. GWP i = Global warming potential for each greenhouse gas from Table A-1 of this subpart. n = The number of greenhouse gases emitted. (5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO 2 that is captured for transfer off site. (c) To calculate GHG emissions for comparison to the 25,000 metric ton CO 2 e/year emission threshold for stationary fuel combustion under paragraph (a)(3) of this section, calculate CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit by following the methods specified in paragraph (b)(2) of this section. Then, convert the emissions of each GHG to metric tons CO 2 e per year using Equation A-1 of this section, and sum the emissions for all units at the facility. (d) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 per year threshold for importers and exporters of coal-to-liquid products under paragraph (a)(4) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete combustion or oxidation of the quantity of coal-to-liquid products that are imported during the reporting year and, that are exported during the reporting year. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO 2 per year threshold. Calculate the quantities using the methodology specified in subpart LL of this part. (e) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 e per year threshold for importers and exporters of petroleum products under paragraph (a)(4) of this section, calculate the mass in metric tons per year of CO 2 that would result from the complete combustion or oxidation of the combined volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO 2 per year threshold. Calculate the quantities using the methodology specified in subpart MM of this part. (f) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO 2 , the owner or operator shall calculate the mass in metric tons per year of CO 2 e imports and exports as described in paragraphs (f)(1) through (f)(3) of this section. Compare the imported quantities and the exported quantities separately to the 25,000 metric ton CO 2 per year threshold. (1) Calculate the mass in metric tons per year of CO 2 , N 2 O, each fluorinated GHG, and each fluorinated heat transfer fluid that is imported and the mass in metric tons per year of CO 2 , N 2 O, each fluorinated GHG, and each fluorinated heat transfer fluid that is exported during the year. (2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO 2 e using Equation A-1 of this section. (3) Sum the total annual metric tons of CO 2 e in paragraph (f)(2) of this section for all imported GHGs. Sum the total annual metric tons of CO 2 e in paragraph (f)(2) of this section for all exported GHGs. (g) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary calculations to determine whether the threshold has been exceeded. (h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements, if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time pursuant to § 98.3(b)(3). Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion. (i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year. (1) If reported CO 2 e emissions, calculated in accordance with § 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 CO 2 e per year. The owner or operator must maintain the corresponding records required under § 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 CO 2 e 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 CO 2 e emissions, calculated in accordance with § 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 CO 2 e per year. The owner or operator must maintain the corresponding records required under § 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 or operator must resume reporting if annual CO 2 e 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. (3) If the operations of a facility or supplier are changed such that all applicable processes and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the owner or operator may discontinue complying with this part for the reporting years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all applicable processes and operations no later than March 31 of the year following such changes. If one or more processes or operations subject to paragraphs (a)(1) through (4) of this section at a facility or supplier cease to operate, but not all applicable processes or operations cease to operate, then the owner or operator is exempt from reporting for any such processes or operations in the reporting years following the reporting year in which cessation of the process or operation occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which the process or operation has ceased for an entire reporting year. Cessation of operations in the context of underground coal mines includes, but is not limited to, abandoning and sealing the facility. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to the municipal solid waste landfills source category (subpart HH of this part), or the industrial waste landfills source category (subpart TT of this part). This paragraph (i)(3) does not apply when there is a change in the owner or operator for facilities in industry segments with a unique definition of facility as defined in § 98.238 of the petroleum and natural gas systems source category (subpart W of this part), unless the changes result in permanent cessation of all applicable processes and operations. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation. (4) The provisions of paragraphs (i)(1) and (2) of this section apply to suppliers subject to subparts LL through QQ of this part by substituting the term “quantity of GHG supplied” for “emissions.” For suppliers, the provisions of paragraphs (i)(1) and (2) apply individually to each importer and exporter and individually to each petroleum refinery, fractionator of natural gas liquids, local natural gas distribution company, and producer of CO 2 , N 2 O, or fluorinated greenhouse gases ( e.g., a supplier of industrial greenhouse gases might qualify to discontinue reporting as an exporter of industrial greenhouse gases but still be required to report as an importer; or a company might qualify to discontinue reporting as a supplier of industrial greenhouse gases under subpart OO of this part but still be required to report as a supplier of carbon dioxide under subpart PP of this part). (5) If the operations of a facility or supplier are changed such that a process or operation no longer meets the “Definition of Source Category” as specified in an applicable subpart, then the owner or operator may discontinue complying with any such subpart for the reporting years following the year in which change occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which such changes persist for an entire reporting year. The owner or operator must resume complying with this part for the process or operation starting in any future calendar year during which the process or operation meets the “Definition of Source Category” as specified in an applicable subpart. (6) If an entire facility or supplier is merged into another facility or supplier that is already reporting GHG data under this part, then the owner or operator may discontinue complying with this part for the facility or supplier, provided that the owner or operator submits a notification to the Administrator that announces the discontinuation of reporting and the e-GGRT identification number of the reconstituted facility no later than March 31 of the year following such changes. (7) If a facility in an industry segment with a unique definition of facility as defined in § 98.238 of the petroleum and natural gas systems source category (subpart W of this part) undergoes the type of change in owner or operator specified in paragraph § 98.4(n)(4) of this subpart, then the prior owner or operator may discontinue complying with the reporting requirements of this part for the facility for the reporting years following the year in which the change in owner or operator occurred, provided that the prior owner or operator submits a notification to the Administrator that announces the discontinuation of reporting no later than March 31 of the year following such change. (j) Table A-2 of this subpart provides a conversion table for some of the common units of measure used in part 98. (k) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 e 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 CO 2 e 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 CO 2 e using equation A-1 to this section. (3) Sum the total annual metric tons of CO 2 e in paragraph (k)(2) of this section for all destroyed fluorinated GHGs and destroyed fluorinated heat transfer fluids." 40:40:23.0.1.1.2.1.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,"§ 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part?",EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39758, July 12, 2010; 75 FR 57685, Sept. 22, 2010; 75 FR 74816, Dec. 1, 2010; 75 FR 79134, Dec. 17, 2010; 75 FR 81344, Dec. 27, 2010; 76 FR 14818, Mar. 18, 2011; 76 FR 53065, Aug. 25, 2011; 76 FR 73899, Nov. 29, 2011; 77 FR 51488, Aug. 24, 2012; 78 FR 71946, Nov. 29, 2013; 79 FR 63779, Oct. 24, 2014; 79 FR 73777, Dec. 11, 2014; 79 FR 77391, Dec. 24, 2014; 81 FR 89249, Dec. 9, 2016; 89 FR 31890, Apr. 25, 2024; 89 FR 91164, Nov. 18, 2024; 90 FR 13088, Mar. 20, 2025; 90 FR 21227, May 19, 2025; 91 FR 9718, Feb. 27, 2026]","The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the Administrator, as specified in this section. (a) General. Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part. (b) Schedule. The annual GHG report for reporting year 2010 must be submitted no later than September 30, 2011. The annual report for reporting years 2011 and beyond must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year, except as provided in paragraphs (b)(1), (5), and (6) of this section. (1) For reporting year 2011, facilities with one or more of the subparts listed in paragraphs (b)(1)(i) through (xi) of this section and suppliers listed in paragraph (b)(1)(xii) of this section are required to submit their annual GHG report no later than September 28, 2012. Facilities and suppliers that are submitting their second annual GHG report in 2012 and that are reporting on one or more subparts listed in paragraphs (b)(1)(i) through (xii) of this section must notify the EPA by March 31, 2012, that they are not required to submit their annual GHG report until September 28, 2012. (i) Electronics Manufacturing (subpart I). (ii) Fluorinated Gas Production (subpart L). (iii) Magnesium Production (subpart T). (iv) Petroleum and Natural Gas Systems (subpart W). (v) Use of Electric Transmission and Distribution Equipment (subpart DD). (vi) Underground Coal Mines (subpart FF). (vii) Industrial Wastewater Treatment (subpart II). (viii) Geologic Sequestration of Carbon Dioxide (subpart RR). (ix) Manufacture of Electric Transmission and Distribution (subpart SS). (x) Industrial Waste Landfills (subpart TT). (xi) Injection of Carbon Dioxide (subpart UU). (xii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ). (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. (3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31. (4) Unless otherwise stated, if the final day of any time period falls on a weekend or a Federal holiday, the time period shall be extended to the next business day. (5) The annual GHG report for reporting year 2024 must be submitted no later than May 30, 2025. (6) The annual GHG report for reporting year 2025 must be submitted no later than October 30, 2026. (c) Content of the annual report. Except as provided in paragraph (d) of this section, each annual GHG report shall contain the following information: (1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point. (2) Year and months covered by the report. (3) Date of submittal. (4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report annual emissions of CO 2 , CH 4 , N 2 O, each fluorinated GHG (as defined in § 98.6), and each fluorinated heat transfer fluid (as defined in § 98.98) as follows. (i) Annual emissions (excluding biogenic CO 2 ) aggregated for all GHG from all applicable source categories, expressed in metric tons of CO 2 e calculated using Equation A-1 of this subpart. For electronics manufacturing (as defined in § 98.90), starting in reporting year 2012 the CO 2 e calculation must include each fluorinated heat transfer fluid (as defined in § 98.98) whether or not it is also a fluorinated GHG. (ii) Annual emissions of biogenic CO 2 aggregated for all applicable source categories, expressed in metric tons. (iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (F) of this section. (A) Biogenic CO 2 . (B) CO 2 (excluding biogenic CO 2 ). (C) CH 4 . (D) N 2 O. (E) Each fluorinated GHG (as defined in § 98.6), except fluorinated gas production facilities must comply with § 98.126(a) rather than this paragraph (c)(4)(iii)(E). If a fluorinated GHG does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated GHG is a member. (F) For electronics manufacturing (as defined in § 98.90), each fluorinated heat transfer fluid (as defined in § 98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of this section. If a fluorinated heat transfer fluid does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated heat transfer fluid is a member. (G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the following identifying information: ( 1 ) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC). ( 2 ) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG or fluorinated heat transfer fluid, then report an identification number assigned by EPA's Substance Registry Services. ( 3 ) Linear chemical formula. (iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data for individual units, processes, activities, and operations as specified in the “Data reporting requirements” section of each applicable subpart of this part. (v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility. (vi) [Reserved] (vii) The owner or operator of a facility is not required to report the data elements specified in Table A-6 of this subpart for calendar years 2010 through 2011 until March 31, 2013. The owner or operator of a facility is not required to report the data elements specified in Table A-7 of this subpart for calendar years 2010 through 2013 until March 31, 2015 (as part of the annual report for reporting year 2014), except as otherwise specified in Table A-7 of this subpart. (viii) Applicable source categories means stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all of the source categories listed in Table A-3 and Table A-4 of this subpart present at the facility. (5) For suppliers, report annual quantities of CO 2 , CH 4 , N 2 O, and each fluorinated GHG (as defined in § 98.6) that would be emitted from combustion or use of the products supplied, imported, and exported during the year. Calculate and report quantities at the following levels: (i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in Table A-5 of this subpart and expressed in metric tons of CO 2 e calculated using Equation A-1 of this subpart. (ii) Quantity of each GHG from each applicable supply category in Table A-5 to this subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the following identifying information: (A) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC). (B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG, then report an identification number assigned by EPA's Substance Registry Services. (C) Linear chemical formula. (iii) Any other data specified in the “Data reporting requirements” section of each applicable subpart of this part. (6) A written explanation, as required under § 98.3(e), if you change emission calculation methodologies during the reporting period. (7) A brief description of each “best available monitoring method” used, the parameter measured using the method, and the time period during which the “best available monitoring method” was used, if applicable. (8) Each parameter for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each parameter. Parameters include not only reported data elements, but any data element required for monitoring and calculating emissions. (9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1). (10) NAICS code(s) that apply to the facility or supplier. (i) Primary NAICS code. Report the NAICS code that most accurately describes the facility or supplier's primary product/activity/service. The primary product/activity/service is the principal source of revenue for the facility or supplier. A facility or supplier that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code. (ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the facility or supplier that are not related to the principal source of revenue. (11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions: (i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company's legal name and physical address as the United States parent company and report 100 percent ownership. (ii) If the facility or supplier is entirely owned by a single United States company that is, itself, owned by another company ( e.g. , it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership. (iii) If the facility or supplier is owned by more than one United States company ( e.g. , company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies, and report the percent ownership of each company. (iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative. (v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company's highest-level company based in the United States as the United States parent company, and report 100 percent ownership. (vi) If the facility or supplier is partially owned by a foreign company and partially owned by one or more U.S. companies, provide the legal name and physical address of the foreign company's highest-level company based in the United States, along with the legal names and physical addresses of the other U.S. parent companies, and report the percent ownership of each of these companies. (vii) If the facility or supplier is a federally owned facility, report “U.S. Government” and do not report physical address or percent ownership. (viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company. (12) For the 2010 reporting year only, facilities that have “part 75 units” ( i.e. units that are subject to subpart D of this part or units that use the methods in part 75 of this chapter to quantify CO 2 mass emissions in accordance with § 98.33(a)(5)) must report annual GHG emissions either in full accordance with paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this section. If the latter reporting option is chosen, you must report: (i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO 2 e calculated using Equation A-1 of this subpart. You must include biogenic CO 2 emissions from part 75 units in these annual emissions, but exclude biogenic CO 2 emissions from any non-part 75 units and other source categories. (ii) Annual emissions of biogenic CO 2 , expressed in metric tons (excluding biogenic CO 2 emissions from part 75 units), aggregated for all applicable source categories. (iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section. (A) Biogenic CO 2 (excluding biogenic CO 2 emissions from part 75 units). (B) CO 2 . You must include biogenic CO 2 emissions from part 75 units in these totals and exclude biogenic CO 2 emissions from other non-part 75 units and other source categories. (C) CH 4 . (D) N 2 O. (E) Each fluorinated GHG (including those not listed in Table A-1 of this subpart). (13) An indication of whether the facility includes one or more plant sites that have been assigned a “plant code” (as defined under § 98.6) by either the Department of Energy's Energy Information Administration or by the EPA's Clean Air Markets Division. (d) Special provisions for reporting year 2010. (1) Best available monitoring methods. During January 1, 2010 through March 31, 2010, owners or operators may use best available monitoring methods for any parameter (e.g., fuel use, daily carbon content of feedstock by process line) 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, 2010. Starting no later than April 1, 2010, 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 paragraphs (d)(2) and (d)(3) of this section. Best available monitoring methods means any of the following methods specified in this paragraph: (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, 2010. (i) Timing of request. The extension request must be submitted to EPA no later than 30 days after the effective date of the GHG reporting rule. (ii) Content of request. Requests must contain the following information: (A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of 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 why the needed equipment could not be obtained and installed before April 1, 2010. (D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, 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 promulgation of this part and April 1, 2010, 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, 2010. The use of best available methods will not be approved beyond December 31, 2010. (3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources. In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of § 98.2(a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by September 30, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2012. The abbreviated facility report must include the following information: (i) Facility name and physical street address including the city, state and zip code. (ii) The year and months covered by the report. (iii) Date of submittal. (iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in § 98.33(a) and expressed in metric tons of CO 2 , CH 4 , N 2 O, and CO 2 e. (v) For each stationary fuel combustion source that meets the criteria specified in § 98.36(f), report any facility operating data or process information used for the GHG emission calculations. A stationary fuel combustion source that does not meet the criteria specified in § 98.36(f) must either report the data specified in this paragraph (d)(3)(v) in the annual report or use verification software according to § 98.5(b) in lieu of reporting the data specified in this paragraph. (vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section. (e) Emission calculations. In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required. (f) Verification. To verify the completeness and accuracy of reported GHG emissions, the Administrator may review the certification statements described in paragraphs (c)(9) and (d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits the Administrator from using additional information to verify the completeness and accuracy of the reports. (g) Recordkeeping. An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph (g). Except as otherwise provided in this paragraph, retain all required records for at least 3 years from the date of submission of the annual GHG report for the reporting year in which the record was generated. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. If the owner or operator of a facility is required under § 98.5(b) to use verification software specified by the Administrator, then all records required for the facility under this part must be retained for at least 5 years from the date of submission of the annual GHG report for the reporting year in which the record was generated, starting with records for reporting year 2010. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part: (1) A list of all units, operations, processes, and activities for which GHG emission were calculated. (2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include but are not limited to the following information in this paragraph (g)(2): (i) The GHG emissions calculations and methods used. For data required by § 98.5(b) to be entered into verification software specified in § 98.5(b), maintain the entered data in the format generated by the verification software according to § 98.5(b). (ii) Analytical results for the development of site-specific emissions factors. (iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters. (iv) Any facility operating data or process information used for the GHG emission calculations. (3) The annual GHG reports. (4) Missing data computations. For each missing data event, also retain a record of the cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment. (5) A written GHG Monitoring Plan. (i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i). (A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data. (B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations. (C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable. (iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime. (iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit. (6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part. (h) Annual GHG report revisions. This paragraph applies to the reporting years for which the owner or operator is required to maintain records for a facility or supplier according to the time periods specified in paragraph (g) of this section. (1) The owner or operator shall submit a revised annual GHG report within 45 days of discovering that an annual GHG report that the owner or operator previously submitted contains one or more substantive errors. The revised report must correct all substantive errors. (2) The Administrator may notify the owner or operator in writing that an annual GHG report previously submitted by the owner or operator contains one or more substantive errors. Such notification will identify each such substantive error. The owner or operator shall, within 45 days of receipt of the notification, either resubmit the report that, for each identified substantive error, corrects the identified substantive error (in accordance with the applicable requirements of this part) or provide information demonstrating that the previously submitted report does not contain the identified substantive error or that the identified error is not a substantive error. (3) A substantive error is an error that impacts the quantity of GHG emissions reported or otherwise prevents the reported data from being validated or verified. (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. (5) The owner or operator shall retain documentation for 3 years to support any revision made to an annual GHG report. (i) Calibration accuracy requirements. The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the applicable flow meter calibration and accuracy requirements of this paragraph (i). The accuracy specifications in this paragraph (i) do not apply where either the use of company records (as defined in § 98.6) or the use of “best available information” is specified in an applicable subpart of this part to quantify fuel usage and/or other parameters. Further, the provisions of this paragraph (i) do not apply to stationary fuel combustion units that use the methodologies in part 75 of this chapter to calculate CO 2 mass emissions. (1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, flow meters that measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in a relevant subpart of this part. Each of these flow meters shall meet the applicable accuracy specification in paragraph (i)(2) or (i)(3) of this section. All other measurement devices ( e.g., weighing devices) that are required by a relevant subpart of this part, and that are used to provide data for the GHG emissions calculations, shall also be calibrated prior to April 1, 2010; however, the accuracy specifications in paragraphs (i)(2) and (i)(3) of this section do not apply to these devices. Rather, each of these measurement devices shall be calibrated to meet the accuracy requirement specified for the device in the applicable subpart of this part, or, in the absence of such accuracy requirement, the device must be calibrated to an accuracy within the appropriate error range for the specific measurement technology, based on an applicable operating standard, including but not limited to manufacturer's specifications and industry standards. The procedures and methods used to quality-assure the data from each measurement device shall be documented in the written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this section. (i) All flow meters and other measurement devices that are subject to the provisions of this paragraph (i) must be calibrated according to one of the following: You may use the manufacturer's recommended procedures; an appropriate industry consensus standard method; or a method specified in a relevant subpart of this part. The calibration method(s) used shall be documented in the monitoring plan required under paragraph (g) of this section. (ii) For facilities and suppliers that become subject to this part after April 1, 2010, all flow meters and other measurement devices (if any) that are required by the relevant subpart(s) of this part to provide data for the GHG emissions calculations shall be installed no later than the date on which data collection is required to begin using the measurement device, and the initial calibration(s) required by this paragraph (i) (if any) shall be performed no later than that date. (iii) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, subsequent recalibrations of the flow meters and other measurement devices subject to the requirements of this paragraph (i) shall be performed at one of the following frequencies: (A) You may use the frequency specified in each applicable subpart of this part. (B) You may use the frequency recommended by the manufacturer or by an industry consensus standard practice, if no recalibration frequency is specified in an applicable subpart. (2) Perform all flow meter calibration at measurement points that are representative of the normal operating range of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph (i)(3) of this section, calculate the calibration error at each measurement point using Equation A-2 of this section. The terms “R” and “A” in Equation A-2 must be expressed in consistent units of measure ( e.g., gallons/minute, ft 3 /min). The calibration error at each measurement point shall not exceed 5.0 percent of the reference value. where: CE = Calibration error (%). R = Reference value. A = Flow meter response to the reference value. where: CE = Calibration error (%). R = Reference value. A = Flow meter response to the reference value. (3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters. (i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A-3 of this subpart. The terms “R,” “A,” and “FS” in Equation A-3 of this subpart must be in consistent units of measure ( e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level ( i.e., at the zero level and at each upscale level) does not exceed 6.0 percent. where: CE = Calibration error (%). R = Reference value. A = Transmitter response to the reference value. FS = Full-scale value of the transmitter. where: CE = Calibration error (%). R = Reference value. A = Transmitter response to the reference value. FS = Full-scale value of the transmitter. (ii) In cases where there are only two transmitters ( i.e., differential pressure and either temperature or total pressure) in the immediate vicinity of the flow meter's primary element ( e.g., the orifice plate), or when there is only a differential pressure transmitter in close proximity to the primary element, calibration of these existing transmitters to a CE of 2.0 percent or less at each measurement point is still required, in accordance with paragraph (i)(3)(i) of this section; alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE values for the two transmitters at each calibration level does not exceed 4.0 percent. However, note that installation and calibration of an additional transmitter (or transmitters) at the flow monitor location to measure temperature or total pressure or both is not required in these cases. Instead, you may use assumed values for temperature and/or total pressure, based on measurements of these parameters at a remote location (or locations), provided that the following conditions are met: (A) You must demonstrate that measurements at the remote location(s) can, when appropriate correction factors are applied, reliably and accurately represent the actual temperature or total pressure at the flow meter under all expected ambient conditions. (B) You must make all temperature and/or total pressure measurements in the demonstration described in paragraph (i)(3)(ii)(A) of this section with calibrated gauges, sensors, transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these devices to an accuracy within the appropriate error range for the specific measurement technology, according to one of the following. You may calibrate using a manufacturer's specification or an industry consensus standard. (C) You must document the methods used for the demonstration described in paragraph (i)(3)(ii)(A) of this section in the written GHG Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must also include the data from the demonstration, the mathematical correlation(s) between the remote readings and actual flow meter conditions derived from the data, and any supporting engineering calculations in the GHG Monitoring Plan. You must maintain all of this information in a format suitable for auditing and inspection. (D) You must use the mathematical correlation(s) derived from the demonstration described in paragraph (i)(3)(ii)(A) of this section to convert the remote temperature or the total pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, on a daily basis. You shall then use the actual temperature and total pressure values to correct the measured flow rates to standard conditions. (E) You shall periodically check the correlation(s) between the remote and actual readings (at least once a year), and make any necessary adjustments to the mathematical relationship(s). (4) Fuel billing meters are exempted from the calibration requirements of this section and from the GHG Monitoring Plan and recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also exempted from the calibration requirements of this section. (5) For a flow meter that has been previously calibrated in accordance with paragraph (i)(1) of this section, an additional calibration is not required by the date specified in paragraph (i)(1) of this section if, as of that date, the previous calibration is still active ( i.e., the device is not yet due for recalibration because the time interval between successive calibrations has not elapsed). In this case, the deadline for the successive calibrations of the flow meter shall be set according to one of the following. You may use either the manufacturer's recommended calibration schedule or you may use the industry consensus calibration schedule. (6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. The subsequent required recalibrations of the flow meters may be similarly postponed. Such postponements shall be documented in the monitoring plan that is required under paragraph (g)(5) of this section. (7) If the results of an initial calibration or a recalibration fail to meet the required accuracy specification, data from the flow meter shall be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibration is completed. You shall follow the missing data provisions provided in the relevant missing data sections during the period of data invalidation. (j) Measurement device installation —(1) General. If an owner or operator required to report under subpart P, subpart X or subpart Y of this part has process equipment or units that operate continuously and it is not possible to install a required flow meter or other measurement device by April 1, 2010, (or by any later date in 2010 approved by the Administrator as part of an extension of best available monitoring methods per paragraph (d) of this section) without process equipment or unit shutdown, or through a hot tap, the owner or operator may request an extension from the Administrator to delay installing the measurement device until the next scheduled process equipment or unit shutdown. If approval for such an extension is granted by the Administrator, the owner or operator must use best available monitoring methods during the extension period. (2) Requests for extension of the use of best available monitoring methods for measurement device installation. The owner or operator must first provide the Administrator an initial notification of the intent to submit an extension request for use of best available monitoring methods beyond December 31, 2010 (or an earlier date approved by EPA) in cases where measurement device installation would require a process equipment or unit shutdown, or could only be done through a hot tap. The owner or operator must follow-up this initial notification with the complete extension request containing the information specified in paragraph (j)(4) of this section. (3) Timing of request. (i) The initial notice of intent must be submitted no later than January 1, 2011, or by the end of the approved use of best available monitoring methods extension in 2010, whichever is earlier. The completed extension request must be submitted to the Administrator no later than February 15, 2011. (ii) Any subsequent extensions to the original request must be submitted to the Administrator within 4 weeks of the owner or operator identifying the need to extend the request, but in any event no later than 4 weeks before the date for the planned process equipment or unit shutdown that was provided in the original or most recently approved request. (4) Content of the request. Requests must contain the following information: (i) Specific measurement device for which the request is being made and the location where each measurement device will be installed. (ii) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) requiring the measurement device. (iii) A description of the reasons why the needed equipment could not be installed before April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under § 98.3(d). (iv) Supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there was no opportunity during 2010 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown. (v) Include a description of the proposed best available monitoring method for estimating GHG emissions during the time prior to installation of the meter. (5) Approval criteria. The owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to install the measurement device before April 1, 2010 (or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under paragraph (d) of this section) without a process equipment or unit shutdown, or through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. The Administrator will not initially approve the use of the proposed best available monitoring method past December 31, 2013. (6) Measurement device installation deadline. Any owner or operator that submits both a timely initial notice of intent and a timely completed extension request under paragraph (j)(3) of this section to extend use of best available monitoring methods for measurement device installation must install all such devices by July 1, 2011 unless the extension request under this paragraph (j) is approved by the Administrator before July 1, 2011. (7) One time extension past December 31, 2013. If an owner or operator determines that a scheduled process equipment or unit shutdown will not occur by December 31, 2013, the owner or operator may re-apply to use best available monitoring methods for one additional time period, not to extend beyond December 31, 2015. To extend use of best available monitoring methods past December 31, 2013, the owner or operator must submit a new extension request by June 1, 2013 that contains the information required in paragraph (j)(4) of this section. The owner or operator must demonstrate to the Administrator's satisfaction that it continues to not be reasonably feasible to install the measurement device before December 31, 2013 without a process equipment or unit shutdown, or that installation of the measurement device could only be done through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. An owner or operator that submits a request under this paragraph to extend use of best available monitoring methods for measurement device installation must install all such devices by December 31, 2013, unless the extension request under this paragraph is approved by the Administrator. (k) Revised global warming potentials and special provisions for reporting year 2013 and subsequent reporting years. This paragraph (k) applies to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 solely due to an amendment to Table A-1 of this subpart. (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. (4) A change in the GWP for one or more compounds includes the addition to Table A-1 of this subpart of either a chemical-specific or a default GWP that applies to a compound to which no chemical-specific GWP in Table A-1 of this subpart previously applied. (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 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." 40:40:23.0.1.1.2.1.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.4 Authorization and responsibilities of the designated representative.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79137, Dec. 17, 2010; 76 FR 73900, Nov. 29, 2011; 81 FR 89249, Dec. 9, 2016; 89 FR 42218, May 14, 2024; 89 FR 91164, Nov. 18, 2024; 90 FR 21227, May 19, 2025]","(a) General. Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40 CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part. (b) Authorization of a designated representative. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on the owners and operators of such facility or supplier and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section. (c) Responsibility of the designated representative. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the designated representative by the Administrator or a court. (d) Timing. No GHG emissions report or other submissions under this part for a facility or supplier will be accepted until the Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the facility's or supplier's initial emission report under this part. (e) Certification of the GHG emissions report. Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and § 3.10 of this chapter. (1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.” (2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section. (f) Alternate designated representative. A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative. (1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative. (i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier. (ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative. (2) Except in this section, whenever the term “designated representative” is used in this part, the term shall be construed to include the designated representative or any alternate designated representative. (g) Changing a designated representative or alternate designated representative. The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the Administrator may be changed at any time upon receipt by the Administrator of another later signed, complete certificate of representation under this section for the facility or supplier. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier. (h) Changes in owners and operators. Except as provided in paragraph (n) of this section, in the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation that is complete under this section except that such list shall be amended to include such owner or operator. (i) Certificate of representation. A certificate of representation shall be complete if it includes the following elements in a format prescribed by the Administrator in accordance with this section: (1) Identification of the facility or supplier for which the certificate of representation is submitted. (2) The name, organization name (company affiliation-employer), address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative. (3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners shall not make the certificate of representation incomplete. (4) The following certification statements by the designated representative and any alternate designated representative: (i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.” (ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.” (iii) “I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier.” (iv) “If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier.” (5) The signature of the designated representative and any alternate designated representative and the dates signed. (6) A list of the subparts that the owners and operators anticipate will be included in the annual GHG report. The list of potentially applicable subparts is required only for an initial certificate of representation that is submitted after January 1, 2018 ( i.e., for a facility or supplier that previously was not registered under this part). The list of potentially applicable subparts does not need to be revised with revisions to the COR or if the actual applicable subparts change. (j) Documents of agreement. Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted. (k) Binding nature of the certificate of representation. Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator. (l) Objections concerning a designated representative. (1) Except as provided in paragraph (g) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the Administrator under this part. (2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative. (m) Delegation by designated representative and alternate designated representative. (1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph. (2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements: (i) The name, organization name (company affiliation-employer) address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative. (ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an “agent”). (iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her. (iv) For each type of electronic submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made. (v) The following certification statements by such designated representative or alternate designated representative: (A) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under § 98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.” (B) “Until this notice of delegation is superseded by a later signed notice of delegation under § 98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under § 98.4(m) is terminated.” (vi) The signature of such designated representative or alternate designated representative and the date signed. (3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority. (4) Any electronic submission covered by the certification in paragraph (m)(2)(v)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation. (n) Alternative provisions for changes in owners and operators for industry segments with a unique definition of facility as defined in § 98.238. When there is a change to the owner or operator of a facility required to report under the onshore petroleum and natural gas production, natural gas distribution, onshore petroleum and natural gas gathering and boosting, or onshore natural gas transmission pipeline industry segments of subpart W of this part, or a change to the owner or operator for some emission sources from the facility in one of these industry segments, the provisions specified in paragraphs (n)(1) through (4) of this section apply for the respective type of change in owner or operator. (1) If the entire facility is acquired by an owner or operator that does not already have a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), then within 90 days after the change in the owner or operator, the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section. If the new owner or operator already had emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, prior to the acquisition in the same basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution) as the acquired facility but had not previously met the applicability requirements in §§ 98.2(a) and 98.231, then per the applicable definition of facility in § 98.238, the previously owned applicable emission sources must be included in the acquired facility. The new owner or operator and the new designated representative shall be responsible for submitting the annual report for the facility for the entire reporting year beginning with the reporting year in which the acquisition occurred. (2) If the entire facility is acquired by an owner or operator that already has a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), the new owner or operator shall merge the acquired facility with their existing facility for purposes of the annual greenhouse gas (GHG) report. The owner or operator shall also follow the provisions of § 98.2(i)(6) to notify EPA that the acquired facility will discontinue reporting and shall provide the e-GGRT identification number of the merged, or reconstituted, facility. The owner or operator of the merged facility shall be responsible for submitting the annual report for the merged facility for the entire reporting year beginning with the reporting year in which the acquisition occurred. (3) If only some emission sources from the facility are acquired by one or more new owners or operators, the existing owner or operator ( i.e., the owner or operator of the portion of the facility that is not sold) shall continue to report under subpart W of this part for the retained emission sources unless and until that facility meets one of the criteria in § 98.2(i). Each owner or operator that acquires emission sources from the facility must account for those acquired emission sources according to paragraph (n)(3)(i) or (ii) of this section, as applicable. (i) If the purchasing owner or operator that acquires only some of the emission sources from the existing facility does not already have a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), the purchasing owner or operator shall begin reporting as a new facility. The new facility must include the acquired emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, and any emission sources the purchasing owner or operator already owned in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution). The designated representative for the new facility must be selected by the purchasing owner or operator according to the schedule and procedure specified in paragraphs (b) through (d) of this section. The purchasing owner or operator shall be responsible for submitting the annual report for the new facility for the entire reporting year beginning with the reporting year in which the acquisition occurred. The purchasing owner or operator shall continue to report under subpart W of this part for the new facility unless and until that facility meets one of the criteria in § 98.2(i). (ii) If the purchasing owner or operator that acquires only some of the emission sources from the existing facility already has a reporting facility in the same industry segment and basin (for onshore petroleum and natural gas production or onshore petroleum and natural gas gathering and boosting) or state (for natural gas distribution), then per the applicable definition of facility in § 98.238, the purchasing owner or operator must add the acquired emission sources specified in § 98.232(c), (i), (j), or (m), as applicable, to their existing facility for purposes of reporting under subpart W of this part. The purchasing owner or operator shall be responsible for submitting the annual report for the entire facility, including the acquired emission sources, for the entire reporting year beginning with the reporting year in which the acquisition occurred. (4) If all the emission sources from a reporting facility are sold to multiple owners or operators within the same reporting year, such that the prior owner or operator of the facility does not retain any of the emission sources, then the prior owner or operator of the facility shall notify EPA within 90 days of the last transaction that all of the facility's emission sources were acquired by multiple purchasers, including the identity of the purchasers. Each owner or operator that acquires emission sources from a facility shall account for those sources according to paragraph (n)(3)(i) or (ii) of this section, as applicable. (o) Alternative provisions for responsibility for submissions and revisions to annual GHG reports for reporting years prior to changes in owners and operators for facilities that report under subpart W of this part. If there is a change to the owner or operator of a facility that reports under subpart W of this part on January 17, 2025 or later and paragraph (o)(3) of this section does not apply, the entity (or entities) that was (were) the owner or operator as of December 31 of each reporting year remains responsible for submission and any revisions to annual reports for that reporting year and if applicable, annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. If paragraph (o)(1) or (o)(2) applies, the seller(s) shall select a historic reporting representative according to paragraph (o)(1) or (o)(2) of this section, as applicable, and according to paragraph (o)(5) of this section who will be responsible for submission (if not already submitted before the transaction) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. If there is a change to the owner or operator of a facility that reports under subpart W of this part that occurs during a transaction that results in the selling owner(s) and operator(s) ceasing to exist or if there is a change in owner or operator that occurs after December 31, 2024 and prior to January 17, 2025, the owner(s) and operators(s) as of December 31, 2024 and buyer(s) shall select a historic reporting representative according to paragraph (o)(3) or (o)(4) of this section, as applicable, and paragraph (o)(5) of this section who will be responsible for submission (if not already submitted before the transaction) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. If an entire facility is merged or acquired by a new owner(s) or operator(s), the owner(s) or operator(s) prior to the transaction must notify EPA of the date of the last transaction that results in a change to the owner or operator of the facility and the acquiring owner(s) or operator(s) must provide the e-GGRT identification number of the facility acquired in the transaction. For facilities that meet the criteria in this paragraph (o), the terms Owner and Operator used in this subpart A and subpart W of this part refer to the owner(s) and operator(s) responsible for submission (if not already submitted before the transaction) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. (1) If a facility reporting under subpart W had a single owner or operator as of December 31 of the year prior to the transaction(s), then within 90 days of a transaction(s) that results in a change to the owner or operator of the facility from the owner or operator as of December 31 of that reporting year, the owner or operator as of December 31 of that reporting year shall select a historic reporting representative who will be responsible for submission (if not already submitted before the transaction(s)) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. The historic reporting representative shall be an individual selected by an agreement binding on the owner or operator as of December 31 of that reporting year, following the provisions of paragraph (b) of this section. (2) If a facility reporting under subpart W had more than one owner or operator as of December 31 of the year prior to the transaction(s), then within 90 days of a transaction(s) that results in a change to the owners or operators of the facility from the owners and operators of that reporting year, the owners and operators, as applicable, as of December 31 of that reporting year, shall select a historic reporting representative who will be responsible for submission (if not already submitted before the transaction(s)) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. The historic reporting representative shall be an individual selected by an agreement binding on each of the owners and operators as of December 31 of that reporting year, following the provisions of paragraph (b) of this section. If the transaction results in a change to the owner(s) or operator(s) for the entire facility, the new owner(s) or operator(s) must notify EPA of the date(s) of each transaction that results in a change to the owner or operator of the facility and must provide the e-GGRT identification number of the facility acquired in the transaction. (3) If a facility is sold by the owner(s) or operator(s) as of December 31 of the year prior to the transaction and the owner(s) or operator(s) selling the facility is(are) acquired or all of the remaining assets of the owner(s) or operators(s) are acquired such that the selling owner(s) or operator(s) cease to exist as a result of a transaction that results in a change to the owner(s) or operator(s) of a facility, the owners or operators involved in that transaction shall select a historic reporting representative who will be responsible for submission (if not already submitted before the transaction) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. The historic reporting representative shall be an individual selected by an agreement binding on each of the owners and operators involved in the transaction, following the provisions of paragraph (b) of this section. If the transaction results in a change to the owner(s) or operator(s) for the entire facility, the new owner(s) or operator(s) must notify EPA of the date(s) of each transaction that results in a change to the owner or operator of the facility and must provide the e-GGRT identification number of the facility acquired in the transaction. (4) If a facility is sold after December 31, 2024 and prior to January 17, 2025, all of the owners or operators involved in that transaction(s) must select a historic reporting representative who will be responsible for submission (if not already submitted before the transaction(s)) and revisions to annual GHG reports under § 98.3(h) for reporting years as specified in paragraph (o)(6) of this section. The historic reporting representative shall be an individual selected by an agreement binding on each of the owners and operators involved in the transaction(s), following the provisions of paragraph (b) of this section. If the transaction results in a change to the owner(s) or operator(s) for the entire facility, the new owner(s) or operator(s) must notify EPA of the date(s) of each transaction that results in a change to the owner or operator of the facility and must provide the e-GGRT identification number of the facility acquired in the transaction. (5) The provisions of paragraphs (b), (c), (e), (f), (g), and (m) of this section apply to the historic reporting representative selected in paragraphs (o)(1) through (4) of this section by substituting the term “historic reporting representative” for “designated representative.” The provisions of paragraph (i) of this section apply to the historic reporting representative by adding the term “historic reporting representative and any historic alternate designated representative to instances of “the designated representative and any alternate designated representative.” (6) Following a transaction as specified in this paragraph (o), the owner(s) or operator(s) relevant as specified in this paragraph (o) (and their selected historic reporting representative as specified in this paragraph (o)) remain responsible for submission (if not already submitted before the transaction) and any revisions to annual reports for the reporting year prior to the transaction and, if applicable, annual GHG reports under § 98.3(h) for additional reporting years prior to the transaction as specified in paragraphs (o)(6)(i) and (ii) of this section. If the responsible owner(s) or operators(s) are acquired such that the owner(s) or operator(s) as of cease to exist as a result of a transaction, the acquiring owners would become responsible for submission (if not already submitted before the transaction) and any revisions to annual reports for the reporting year prior to the transaction and, if applicable, annual GHG reports under § 98.3(h) for additional reporting years prior to the transaction as specified in paragraphs (o)(6)(i) and (ii) of this section. (i) For the first transaction that occurs as specified in this paragraph (o), all reporting years prior to the reporting year prior to the transaction. (ii) For each transaction after the first transaction that occurs as specified in this paragraph (o), all reporting years prior to the reporting year in which the transaction occurred and for which the owner(s) or operator(s) was (were) the owner(s) or operator(s) for the facility as of December 31st of the reporting year (and for which the historic reporting representative represents)." 40:40:23.0.1.1.2.1.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.5 How is the report submitted?,EPA,,,"[79 FR 63780, Oct. 24, 2014, as amended at 79 FR 73778, Dec. 11, 2014; 89 FR 31891, Apr. 25, 2024]","(a) Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of § 98.4 and in a format specified by the Administrator. (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." 40:40:23.0.1.1.2.1.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.6 Definitions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39759, July 12, 2010; 75 FR 57686, Sept. 22, 2010; 75 FR 66457, Oct. 28, 2010; 75 FR 74487, Nov. 30, 2010; 75 FR 74816, Dec. 1, 2010; 75 FR 79137, Dec. 17, 2010; 76 FR 73900, Nov. 29, 2011; 76 FR 80573, Dec. 23, 2011; 78 FR 71948, Nov. 29, 2013; 79 FR 70385, Nov. 25, 2014; 79 FR 73778, Dec. 11, 2014; 81 FR 89249, Dec. 9, 2016; 81 FR 89250, Dec. 9, 2016; 89 FR 31891, Apr. 25, 2024; 89 FR 42219, May 14, 2024]","All terms used in this part shall have the same meaning given in the Clean Air Act and in this section. Absorbent circulation pump means a pump commonly powered by natural gas pressure that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor. Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level. Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for the reduction of sulfur dioxide and nitrogen oxides emissions. Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's authorized representative. AGA means the American Gas Association Agricultural by-products means those parts of arable crops that are not used for the primary purpose of producing food. Agricultural by-products include, but are not limited to, oat, corn and wheat straws, bagasse, peanut shells, rice and coconut husks, soybean hulls, palm kernel cake, cottonseed and sunflower seed cake, and pomace. Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of gas. Alkali bypass means a duct between the feed end of the kiln and the preheater tower through which a portion of the kiln exit gas stream is withdrawn and quickly cooled by air or water to avoid excessive buildup of alkali, chloride and/or sulfur on the raw feed. This may also be referred to as the “kiln exhaust gas bypass.” Anaerobic digester means the system where wastes are collected and anaerobically digested in large containment vessels or covered lagoons. Anaerobic digesters stabilize waste by the microbial reduction of complex organic compounds to CO2 and CH4, which is captured and may be flared or used as fuel. Anaerobic digestion systems, include but are not limited to covered lagoon, complete mix, plug flow, and fixed film digesters. Anaerobic lagoon , with respect to subpart JJ of this part, means a type of liquid storage system component that is designed and operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention time (up to a year or greater), depending on the climate region, volatile solids loading rate, and other operational factors. Anode effect is a process upset condition of an aluminum electrolysis cell caused by too little alumina dissolved in the electrolyte. The anode effect begins when the voltage rises rapidly and exceeds a threshold voltage, typically 8 volts. Anode Effect Minutes per Cell Day (24 hours) are the total minutes during which an electrolysis cell voltage is above the threshold voltage, typically 8 volts. ANSI means the American National Standards Institute. API means the American Petroleum Institute. ASABE means the American Society of Agricultural and Biological Engineers. ASME means the American Society of Mechanical Engineers. ASTM means ASTM, International. Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts. Aviation Gasoline means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in aviation reciprocating engines. Specifications can be found in ASTM Specification D910-07a, Standard Specification for Aviation Gasolines (incorporated by reference, see § 98.7). B 0 means the maximum CH 4 producing capacity of a waste stream, kg CH 4 /kg COD. Basic oxygen furnace means any refractory-lined vessel in which high-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel. bbl means barrel. Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels. Biogenic CO 2 means carbon dioxide emissions generated as the result of biomass combustion from combustion units for which emission calculations are required by an applicable part 98 subpart. Biomass means non-fossilized and biodegradable organic material originating from plants, animals or micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material. Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials. Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus. Blendstocks—Others are products used for blending or compounding into finished motor gasoline that are not defined elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock (DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus. Blowdown mean the act of emptying or depressuring a vessel. This may also refer to the discarded material such as blowdown water from a boiler or cooling tower. Blowdown vent stack emissions mean natural gas and/or CO 2 released due to maintenance and/or blowdown operations including compressor blowdown and emergency shut-down (ESD) system testing. British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit. Bulk, with respect to industrial GHG suppliers and CO 2 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 CO 2 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 CO 2 that is contained in a manufactured product such as electrical equipment, appliances, aerosol cans, or foams is not a bulk substance. Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to fractionators or to refineries and petrochemical plants where the fractionation takes place. Butane , or n-Butane, is a paraffinic straight-chain hydrocarbon with molecular formula C 4 H 10 . Butylene , or n-Butylene, is an olefinic straight-chain hydrocarbon with molecular formula C 4 H 8 . By-product coke oven battery means a group of ovens connected by common walls, where coal undergoes destructive distillation under positive pressure to produce coke and coke oven gas from which by-products are recovered. Calcination means the process of thermally treating minerals to decompose carbonates from ore. Calculation methodology means a methodology prescribed under the section “Calculating GHG Emissions” in any subpart of part 98. Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its calibrated volume. Carbon dioxide equivalent or CO 2 e means the number of metric tons of CO 2 emissions with the same global warming potential as one metric ton of another greenhouse gas, and is calculated using Equation A-1 of this subpart. Carbon dioxide production well means any hole drilled in the earth for the primary purpose of extracting carbon dioxide from a geologic formation or group of formations which contain deposits of carbon dioxide. Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity. Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered part of the same CO 2 production well facility if they otherwise meet the definition. 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. Carbon share means the percent of total mass that carbon represents in any product. Carbonate means compounds containing the radical CO 3 −2 . Upon calcination, the carbonate radical decomposes to evolve carbon dioxide (CO 2 ). Common carbonates consumed in the mineral industry include calcium carbonate (CaCO 3 ) or calcite; magnesium carbonate (MgCO 3 ) or magnesite; and calcium-magnesium carbonate (CaMg(CO 3 ) 2 ) or dolomite. Carbonate-based mineral means any of the following minerals used in the manufacture of glass: Calcium carbonate (CaCO 3 ), calcium magnesium carbonate (CaMg(CO 3 ) 2 ), sodium carbonate (Na 2 CO 3 ), barium carbonate (BaCO 3 ), potassium carbonate (K 2 CO 3 ), lithium carbonate (Li 2 CO 3 ), and strontium carbonate (SrCO 3 ). Carbonate-based mineral mass fraction means the following: For limestone, the mass fraction of calcium carbonate (CaCO 3 ) in the limestone; for dolomite, the mass fraction of calcium magnesium carbonate (CaMg(CO 3 ) 2 ) in the dolomite; for soda ash, the mass fraction of sodium carbonate (Na 2 CO 3 ) in the soda ash; for barium carbonate, the mass fraction of barium carbonate (BaCO 3 ) in the barium carbonate; for potassium carbonate, the mass fraction of potassium carbonate (K 2 CO 3 ) in the potassium carbonate; for lithium carbonate, the mass fraction of lithium carbonate (Li 2 CO 3 ); and for strontium carbonate, the mass fraction of strontium carbonate (SrCO 3 ). Carbonate-based raw material means any of the following materials used in the manufacture of glass: Limestone, dolomite, soda ash, barium carbonate, potassium carbonate, lithium carbonate, and strontium carbonate. Carbonofluoridates means fluorinated GHGs that are composed of a -OCF(O) group (carbonyl group with a single-bonded oxygen atom and a fluorine atom) that is linked on the single-bonded oxygen to another hydrocarbon group in which one or more of the hydrogen atoms may be replaced by fluorine atoms. Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery. CBOB-Summer (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Summer. CBOB-Winter (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Winter. Cement kiln dust means non-calcined to fully calcined dust produced in the kiln or pyroprocessing line. Cement kiln dust is a fine-grained, solid, highly alkaline material removed from the cement kiln exhaust gas by scrubbers (filtration baghouses and/or electrostatic precipitators). Centrifugal compressor means any equipment that increases the pressure of a process natural gas or CO 2 by centrifugal action, employing rotating movement of the driven shaft. Centrifugal compressor dry seal emissions mean natural gas or CO 2 released from a dry seal vent pipe and/or the seal face around the rotating shaft where it exits one or both ends of the compressor case. Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor case that operates mechanically under the opposing forces to prevent natural gas or CO 2 from escaping to the atmosphere. Centrifugal compressor wet seal degassing vent emissions means emissions that occur when the high-pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas or CO 2 . High-pressure oil is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by the oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and recirculated. The separated gas is commonly vented to the atmosphere. Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate to within 2 percent of the value on the label or calibration gases. CH 4 means methane. Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals. Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes. Chloride process means a production process where titanium dioxide is produced using calcined petroleum coke and chlorine as raw materials. City gate means a location at which natural gas ownership or control passes from one party to another, neither of which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to customers. CO 2 means carbon dioxide. Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388-05 Standard Classification of Coals by Rank (incorporated by reference, see § 98.7). COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136. Cogeneration unit means a unit that produces electrical energy and useful thermal energy for industrial, commercial, or heating or cooling purposes, through the sequential or simultaneous use of the original fuel energy. Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit burner. Cokemaking means the production of coke from coal in either a by-product coke oven battery or a non-recovery coke oven battery. Commercial applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to another if it otherwise meets the definition. Company records means, 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 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. Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, “T's” or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this part. Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification System 327213 (NAICS 327213). Continuous bleed means a continuous flow of pneumatic supply natural gas to the process control device ( e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas pressure in the valve actuator. Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources. Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding. Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional gasoline for oxygenate blending (CBOB) as well as other blendstock. Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional blendstock for oxygenate blending (CBOB) as well as other blendstock. Crude oil means a mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. (1) Depending upon the characteristics of the crude stream, it may also include any of the following: (i) Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric conditions (temperature and pressure) after being recovered from oil well (casing-head) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included. (ii) Small amounts of non-hydrocarbons, such as sulfur and various metals. (iii) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale. (iv) Petroleum products that are received or produced at a refinery and subsequently injected into a crude supply or reservoir by the same refinery owner or operator. (2) Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content. Cyclic, in the context of fluorinated GHGs, means a fluorinated GHG in which three or more carbon atoms are connected to form a ring. Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24 hours of excretion. Day means any consistently designated 24 hour period during which an emission unit is operated. Decarburization vessel means any vessel used to further refine molten steel with the primary intent of reducing the carbon content of the steel, including but not limited to vessels used for argon-oxygen decarburization and vacuum oxygen decarburization. Deep bedding systems for cattle swine means a manure management system in which, as manure accumulates, bedding is continually added to absorb moisture over a production cycle and possibly for as long as 6 to 12 months. This manure management system also is known as a bedded pack manure management system and may be combined with a dry lot or pasture. Degasification system means the entirety of the equipment that is used to drain gas from underground coal mines. This includes all degasification wells and gob gas vent holes at the underground coal mine. Degasification systems include gob and premine surface drainage wells, gob and premine in-mine drainage wells, and in-mine gob and premine cross-measure borehole wells. Degradable organic carbon (DOC) means the fraction of the total mass of a waste material that can be biologically degraded. Dehydrator means a device in which a liquid absorbent (including ethylene glycol, diethylene glycol, or triethylene glycol) or desiccant directly contacts a natural gas stream to remove water vapor. Dehydrator vent emissions means natural gas and CO 2 released from a natural gas dehydrator system absorbent (typically glycol) regenerator still vent and, if present, a flash tank separator, to the atmosphere, flare, regenerator fire-box/fire tubes, or vapor recovery system. Emissions include stripping natural gas and motive natural gas used in absorbent circulation pumps. Delayed coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator. De-methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons ( e.g., ethane, propane, butane, pentane-plus) in feed natural gas stream. Density means the mass contained in a given unit volume (mass/volume). Desiccant means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include, but are not limited to, molecular sieves, activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor. Destruction means: (1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion, and methane that is collected for any other on-site or off-site use as a fuel. (2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. Destruction device , for the purposes of subparts II and TT of this part, means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas or wastewater biogas. Destruction efficiency means the efficiency with which a destruction device reduces the mass of a greenhouse gas fed into the device. Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The destruction efficiency is expressed in Equation A-2 of this section: where: DE = Destruction Efficiency tGHG iIN = The mass of GHG i fed into the destruction device tGHG iOUT = The mass of GHG i exhausted from the destruction device where: DE = Destruction Efficiency tGHG iIN = The mass of GHG i fed into the destruction device tGHG iOUT = The mass of GHG i exhausted from the destruction device Diesel—Other is any distillate fuel oil not defined elsewhere, including Diesel Treated as Blendstock (DTAB). DIPE (diisopropyl ether, (CH 3 ) 2 CHOCH(CH 3 ) 2 ) is an ether as described in “Oxygenates.” 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. Direct liquefaction means the conversion of coal directly into liquids, rather than passing through an intermediate gaseous state. Direct reduction furnace means a high temperature furnace typically fired with natural gas to produce solid iron from iron ore or iron ore pellets and coke, coal, or other carbonaceous materials. Distillate fuel oil means a classification for one of the petroleum fractions produced in conventional distillation operations and from crackers and hydrotreating process units. The generic term distillate fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4). Distillate Fuel No. 1 has a maximum distillation temperature of 550 °F at the 90 percent recovery point and a minimum flash point of 100 °F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). Distillate Fuel No. 2 has a minimum and maximum distillation temperature of 540 °F and 640 °F at the 90 percent recovery point, respectively, and includes fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm). Distillate Fuel No. 4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 °F. DOC f means the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions within the landfill. Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically. Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials with electric arcs from carbon electrodes. Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This definition excludes EAFs at steel foundries and EAFs used to produce nonferrous metals. Electrothermic furnace means a furnace that heats the charged materials with electric arcs from carbon electrodes. Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator. Emergency equipment means any auxiliary fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations. ETBE (ethyl tertiary butyl ether, (CH 3 ) 3 COC 2 H) is an ether as described in “Oxygenates.” Ethane is a paraffinic hydrocarbon with molecular formula C 2 H 6 . Ethanol is an anhydrous alcohol with molecular formula C 2 H 5 OH. Ethylene is an olefinic hydrocarbon with molecular formula C 2 H 4 . Ex refinery gate means the point at which a petroleum product leaves the refinery. Experimental furnace means a glass melting furnace with the sole purpose of operating to evaluate glass melting processes, technologies, or glass products. An experimental furnace does not produce glass that is sold (except for further research and development purposes) or that is used as a raw material for non-experimental furnaces. Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act. Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the United States to another country or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction. Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties. Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed to the kiln. Feed does not include the fuels used in the kiln to produce heat to form the clinker product. Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical or physical methods into products and by-products. Supplemental fuel burned to provide heat or thermal energy is not a feedstock. Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms. Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame. Flat glass means glass made of soda-lime recipe and produced into continuous flat sheets and other products listed in NAICS 327211. Flowmeter means a device that measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters). Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: A traditional fluid coking unit in which only a small portion of the coke produced in the unit is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to generate a low value fuel gas that is used as fuel in other combustion sources at the refinery. Fluorinated acetates means fluorinated GHGs that are composed of an acetate group with one or more valence locations on the methyl group of the acetate occupied by fluorine atoms ( e.g., CFH 2 C(O)O-, CF 2 HC(O)O-) and, linked to the single-bonded oxygen of the acetate group, another hydrocarbon group in which one or more of the hydrogen atoms may be replaced by fluorine atoms. Fluorinated alcohols other than fluorotelomer alcohols means fluorinated GHGs that include an alcohol functional group (-OH) and that do not meet the definition of fluorotelomer alcohols. Fluorinated formates means fluorinated GHGs that are composed of a formate group -OCH(O) (carbonyl group with a single-bonded oxygen, and with a hydrogen atom) that is linked on the single-bonded oxygen atom to a hydrocarbon group in which one or more of the hydrogen atoms in the hydrocarbon group is replaced by fluorine atoms; the typical formula for fluorinated formates is F n ROCH(O). Fluorinated greenhouse gas (GHG) means sulfur hexafluoride (SF 6 ), 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; (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 °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. Fluorotelomer alcohols means fluorinated GHGs with the chemical formula C n F 2n + 1 CH 2 CH 2 OH. Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, for purpose of creating useful heat. Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane-plus (C5 + ). Plants that only process natural gas but do not fractionate NGLs further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas and fractionate bulk NGLs received from other plants. Fuel means solid, liquid or gaseous combustible material. Fuel gas means gas generated at a petroleum refinery or petrochemical plant and that is combusted separately or in any combination with any type of gas. Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and, if necessary, units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects fuel gas from one or more sources for treatment, as necessary, and transport to a stationary combustion unit. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the various combustion units at the refinery or petrochemical plant. Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in which all available valence locations are filled by fluorine atoms. This includes but is not limited to: Saturated perfluorocarbons; SF 6 ; NF 3 ; SF 5 CF 3 ; fully fluorinated linear, branched, and cyclic alkanes; fully fluorinated ethers; fully fluorinated tertiary amines; fully fluorinated aminoethers; and perfluoropolyethers. Furnace slag means a by-product formed in metal melting furnaces when slagging agents, reducing agents, and/or fluxes ( e.g., coke ash, limestone, silicates) are added to remove impurities from the molten metal. Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from different locations in the landfill by means of a fan or similar mechanical draft equipment (forced convection) to a single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a compressor. A single landfill may have multiple gas collection systems. Landfill gas collection systems do not include “passive” systems, whereby landfill gas flows naturally (without forced convection) to the surface of the landfill where an opening or pipe (vent) is installed to allow for the flow of landfill gas to the atmosphere or to a remote flare installed to combust landfill gas that is passively emitted from the vent. Landfill gas collection systems also do not include “active venting” systems, whereby landfill gas is conveyed to the surface of the landfill using forced convection, but the landfill gas is never recovered or thermally destroyed prior to release to the atmosphere. Gas conditions mean the actual temperature, volume, and pressure of a gas sample. Gas-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of gaseous fuels, and the remainder of its annual heat input from the combustion of fuel oil or other liquid fuels. Gas monitor means an instrument that continuously measures the concentration of a particular gaseous species in the effluent of a stationary source. Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure. Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure conditions and that is combusted to produce heat and/or energy. Gasification means the conversion of a solid or liquid raw material into a gas. Gasoline—Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock). Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass. Glass produced means the weight of glass exiting a glass melting furnace. Global warming potential or GWP means the ratio of the time-integrated radiative forcing from the instantaneous release of one kilogram of a trace substance relative to that of one kilogram of a reference gas ( i.e., CO 2 ). GWPs for each greenhouse gas are provided in Table A-1 of this subpart. For purposes of the calculations in this part, if the GHG has a chemical-specific GWP listed in Table A-1, use that GWP. Otherwise, use the default GWP provided in Table A-1 for the fluorinated GHG group of which the GHG is a member. GPA means the Gas Processors Association. Greenhouse gas or GHG means carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), and fluorinated greenhouse gases (GHGs) as defined in this section. GTBA (gasoline-grade tertiary butyl alcohol, (CH 3 ) 3 COH), or t-butanol, is an alcohol as described in “Oxygenates.” Heavy Gas Oils are petroleum distillates with an approximate boiling range from 651 °F to 1,000 °F. Heel means the amount of gas that remains in a shipping container after it is discharged or off-loaded (that is no more than ten percent of the volume of the container). High-bleed pneumatic devices are automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour. High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid state. Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon. Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing, or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions: (1) Off-loading used or excess fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing. (2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin. (3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention. (4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes. Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate: (1) The consignee. (2) The importer of record. (3) The actual owner. (4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred. Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces. Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas. In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream. Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for automatically maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge all or a portion of the full volume of the actuator intermittently when control action is necessary, but does not bleed continuously. Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C 4 H 10 . Isobutylene is an olefinic branch chain hydrocarbon with molecular formula C 4 H 8 . Kerosene is a light petroleum distillate with a maximum distillation temperature of 400 °F at the 10-percent recovery point, a final maximum boiling point of 572 °F, a minimum flash point of 100 °F, and a maximum freezing point of −22 °F. Included are No. 1-K and No. 2-K, distinguished by maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein). Kerosene-type jet fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of 400 °F at the 10 percent recovery point and a final maximum boiling point of 572 °F. Included are Jet A, Jet A-1, JP-5, and JP-8. Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based substance. Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40 CFR 257.2. Landfill gas means gas produced as a result of anaerobic decomposition of waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being carbon dioxide. Liberated means released from coal and surrounding rock strata during the mining process. This includes both methane emitted from the ventilation system and methane drained from degasification systems. Lime is the generic term for a variety of chemical compounds that are produced by the calcination of limestone or dolomite. These products include but are not limited to calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic hydrate. Liquid/Slurry means a manure management component in which manure is stored as excreted or with some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods less than one year. Low-bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour. Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced from distillates or residues. Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical pulp mills to replace chemicals lost in the process. Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: Static, in vessel, intensive windrow and passive windrow. Static composting typically occurs in an enclosed channel, with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration. Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as of the initial installation of the unit, as specified by the manufacturer. Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40 CFR 60.58b(j). Mcf means thousand cubic feet. Methane conversion factor means the extent to which the CH 4 producing capacity (B o ) is realized in each type of treatment and discharge pathway and system. Thus, it is an indication of the degree to which the system is anaerobic. Methane correction factor means an adjustment factor applied to the methane generation rate to account for portions of the landfill that remain aerobic. The methane correction factor can be considered the fraction of the total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or other cover materials have a methane correction factor of 1. Methanol (CH 3 OH) is an alcohol as described in “Oxygenates.” Midgrade gasoline has an octane rating greater than or equal to 88 and less than or equal to 90. This definition applies to the midgrade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For midgrade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB. Miscellaneous products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric acid. MMBtu means million British thermal units. Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations. Mscf means thousand standard cubic feet. MTBE (methyl tertiary butyl ether, (CH 3 ) 3 COCH 3 ) is an ether as described in “Oxygenates.” Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned. Municipal solid waste or MSW means solid phase household, commercial/retail, and/or institutional waste. Household waste includes material discarded by single and multiple residential dwellings, hotels, motels, and other similar permanent or temporary housing establishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, non-manufacturing activities at industrial facilities, and other similar establishments or facilities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at prisons and government facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional wastes include yard waste, refuse-derived fuel, and motor vehicle maintenance materials. Insofar as there is separate collection, processing and disposal of industrial source waste streams consisting of used oil, wood pallets, construction, renovation, and demolition wastes (which includes, but is not limited to, railroad ties and telephone poles), paper, clean wood, plastics, industrial process or manufacturing wastes, medical waste, motor vehicle parts or vehicle fluff, or used tires that do not contain hazardous waste identified or listed under 42 U.S.C. § 6921, such wastes are not municipal solid waste. However, such wastes qualify as municipal solid waste where they are collected with other municipal solid waste or are otherwise combined with other municipal solid waste for processing and/or disposal. Municipal wastewater treatment plant means a series of treatment processes used to remove contaminants and pollutants from domestic, business, and industrial wastewater collected in city sewers and transported to a centralized wastewater treatment system such as a publicly owned treatment works (POTW). N 2 O means nitrous oxide. Naphthas (<401 °F) is a generic term applied to a petroleum fraction with an approximate boiling range between 122 °F and 400 °F. The naphtha fraction of crude oil is the raw material for gasoline and is composed largely of paraffinic hydrocarbons. Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane. Natural gas may be field quality or pipeline quality. Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm. Natural gas liquids (NGLs) means those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGLs refers to mixtures of NGLs that are sold or delivered as undifferentiated product from natural gas processing plants. Natural gasoline means a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) extracted from natural gas. It includes isopentane. NIST means the United States National Institute of Standards and Technology. Nitric acid production line means a series of reactors and absorbers used to produce nitric acid. Nitrogen excreted is the nitrogen that is excreted by livestock in manure and urine. Non-crude feedstocks means any petroleum product or natural gas liquid that enters the refinery to be further refined or otherwise used on site. Non-recovery coke oven battery means a group of ovens connected by common walls and operated as a unit, where coal undergoes destructive distillation under negative pressure to produce coke, and which is designed for the combustion of the coke oven gas from which by-products are not recovered. North American Industry Classification System (NAICS) code(s) means the six-digit code(s) that represents the product(s)/activity(s)/service(s) at a facility or supplier as listed in the Federal Register and defined in “North American Industrial Classification System Manual 2007,” available from the U.S. Department of Commerce, National Technical Information Service, Alexandria, VA 22312, phone (703) 605-6000 or (800) 553-6847. http://www.census.gov/eos/www/naics/. Oil-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of fuel oil, and the remainder of its annual heat input from the combustion of natural gas or other gaseous fuels. Open-ended valve or lines (OELs) means any valve, except pressure relief valves, having one side of the valve seat in contact with process fluid and one side open to atmosphere, either directly or through open piping. Operating hours means the duration of time in which a process or process unit is utilized; this excludes shutdown, maintenance, and standby. Operational change means, for purposes of § 98.3(b), a change in the type of feedstock or fuel used, a change in operating hours, or a change in process production rate. Operator means any person who operates or supervises a facility or supplier. Other oils (>401 °F) are oils with a boiling range equal to or greater than 401 °F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere. Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in 43 U.S.C. 1331, and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall not be considered an “owner” of the facility or supplier. Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol. Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed. Pentanes plus, or C5 + , is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate. Perfluorocarbons or PFCs means a class of greenhouse gases consisting on the molecular level of carbon and fluorine. Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of carbon black. Petrochemical feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is usually divided into naphthas less than 401 °F and other oils greater than 401 °F. Petroleum means oil removed from the earth and the oil derived from tar sands and shale. Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is also known as marketable coke or catalyst coke. Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum-based feedstocks, including petroleum products derived from co-processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes waxes. Physical address, with respect to a United States parent company as defined in this section, means the street address, city, state and zip code of that company's physical location. Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a slatted floor in an enclosed animal confinement facility. This usually occurs with little or no added water for periods less than one year. Plant code means either of the following: (1) The Plant ID code assigned by the Department of Energy's Energy Information Administration. The Energy Information Administration Plant ID code is also referred to as the “ORIS code”, “ORISPL code”, “Facility ID”, or “Facility code”, among other names. (2) If a Plant ID code has not been assigned by the Department of Energy's Energy Information Administration, then plant code means a code beginning with “88” assigned by the EPA's Clean Air Markets Division for electronic reporting. Portable means designed and capable of being carried or moved from one location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following conditions exists: (1) The equipment is attached to a foundation. (2) The equipment or a replacement resides at the same location for more than 12 consecutive months. (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year. (4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition. Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl. Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it accumulates. The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly. Precision of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level. Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB. Pressed and blown glass means glass which is pressed, blown, or both, into products such as light bulbs, glass fiber, technical glass, and other products listed in NAICS 327212. Pressure relief device or pressure relief valve or pressure safety valve means a safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A common pressure relief device is but not limited to a spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum are not pressure relief devices. Primary fuel means the fuel that provides the greatest percentage of the annual heat input to a stationary fuel combustion unit. Process emissions means the emissions from industrial processes (e.g., cement production, ammonia production) involving chemical or physical transformations other than fuel combustion. For example, the calcination of carbonates in a kiln during cement production or the oxidation of methane in an ammonia process results in the release of process CO 2 emissions to the atmosphere. Emissions from fuel combustion to provide process heat are not part of process emissions, whether the combustion is internal or external to the process equipment. Process unit means the equipment assembled and connected by pipes and ducts to process raw materials and to manufacture either a final product or an intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts. 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. Propane is a paraffinic hydrocarbon with molecular formula C 3 H 8 . Propylene is an olefinic hydrocarbon with molecular formula C 3 H 6 . Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln or fluidized bed calciner) used at a kraft or soda pulp mill to calcine lime mud, which consists primarily of calcium carbonate, into quicklime, which is calcium oxide. Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower. Raw mill means a ball and tube mill, vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated with the raw mill. RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Summer. RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Winter. Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas or CO 2 by positive displacement, employing linear movement of a shaft driving a piston in a cylinder. Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas or CO 2 that escapes to the atmosphere. Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature that will condense natural gas to a liquid. Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock. Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category includes Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock. Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB. 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. Rendered animal fat, or tallow, means fats extracted from animals which are generally used as a feedstock in making biodiesel. Reporting year means the calendar year during which the GHG data are required to be collected for purposes of the annual GHG report. For example, reporting year 2014 is January 1, 2014 through December 31, 2014, and the annual report for reporting year 2014 is submitted to EPA on March 31, 2015. Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale, except in a de minimis manner. Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131 °F. Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes. It has a minimum flash point of 140 °F. Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 °F. Road oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous. Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination. Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the owner or operator based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials. Sales oil means produced crude oil or condensate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge. Saturated chlorofluorocarbons (CFCs) means fluorinated GHGs that contain only chlorine, fluorine, and carbon and that contain only single bonds. Saturated hydrochlorofluoroethers (HCFEs) means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which two or more, but not all, of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms and chlorine atoms; and which contain only single bonds. Saturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are hydrofluorocarbons and that contain only single bonds. Saturated hydrofluoroethers (HFEs) means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which one or more, but not all, of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms; and which contain only single bonds. Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing or the addition of blendstocks. Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on-system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas. Sendout is measured at the city gate station, and other on-system receipt points from storage, peak shaving, and production. Sensor means a device that measures a physical quantity/quality or the change in a physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level. SF 6 means sulfur hexafluoride. Shutdown means the cessation of operation of an emission source for any purpose. Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke. Sinter process means a process that produces a fused aggregate of fine iron-bearing materials suited for use in a blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft combustion and heat sufficient to produce a fused sinter product. Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located. Smelting furnace means a furnace in which lead-bearing materials, carbon-containing reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag. Solid by-products means plant matter such as vegetable waste, animal materials/wastes, and other solid biomass, except for wood, wood waste, and sulphite lyes (black liquor). Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation. Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas. Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide (H 2 S)and/or carbon dioxide (CO 2 ) that exceed the concentrations specified for commercially saleable natural gas delivered from transmission and distribution pipelines. Special naphthas means all finished products with the naphtha boiling range (290 ° to 470 °F) that are generally used as paint thinners, cleaners or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D1836-07, Standard Specification for Commercial Hexanes, and D235-02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline, or that are to be used as petrochemical and synthetic natural gas (SNG) feedstocks are excluded. Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery combustion unit. Spent pulping liquor means the residual liquid collected from on-site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery combustion units at sulfite or semi-chemical pulp facilities. Standard conditions or standard temperature and pressure (STP), for the purposes of this part, means either 60 or 68 degrees Fahrenheit and 14.7 pounds per square inch absolute. Steam reforming means a catalytic process that involves a reaction between natural gas or other light hydrocarbons and steam. The result is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water. Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene. Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support. Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H 2 S) and/or sulfur dioxide (SO 2 ) from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes: Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units are a single sulfur recovery plant only when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are separate sulfur recovery plants. Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process itself. Supplier means a producer, importer, or exporter in any supply category included in Table A-5 to this subpart, as defined by the corresponding subpart of this part. Sweet gas is natural gas with low concentrations of hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2 ) that does not require (or has already had) acid gas treatment to meet pipeline corrosion-prevention specifications for transmission and distribution. Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants. TAME means tertiary amyl methyl ether, (CH 3 ) 2 (C 2 H 5 )COCH 3 ). Trace concentrations means concentrations of less than 0.1 percent by mass of the process stream. Transform means to use and entirely consume (except for trace concentrations) nitrous oxide or fluorinated GHGs in the manufacturing of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide. Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United States or its territories to a second foreign state of final destination, as long as the shipment does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition. Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g., Na2CO 3 .NaHCO 3 .2H 2 O). Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material. Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending. United States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presidential Proclamation No. 5928. United States parent company(s) means the highest-level United States company(s) with an ownership interest in the facility or supplier as of December 31 of the year for which data are being reported. 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 halogenated ethers means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which one or more of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms; and which contain one or more bonds that are not single bonds. Unsaturated ethers include unsaturated HFEs. 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. Unsaturated hydrochlorofluorocarbons (HCFCs) means fluorinated GHGs that contain only carbon, chlorine, fluorine, and hydrogen and that contain one or more bonds that are not single bonds. Unsaturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are hydrofluorocarbons and that contain one or more bonds that are not single bonds. Unsaturated perfluorocarbons (PFCs) means fluorinated GHGs that are perfluorocarbons and that contain one or more bonds that are not single bonds. Unstabilized crude oil means, for the purposes of this part, crude oil that is pumped from the well to a pipeline or pressurized storage vessel for transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater. Used oil means a petroleum-derived or synthetically-derived oil whose physical properties have changed as a result of handling or use, such that the oil cannot be used for its original purpose. Used oil consists primarily of automotive oils ( e.g., used motor oil, transmission oil, hydraulic fluids, brake fluid, etc. ) and industrial oils ( e.g., industrial engine oils, metalworking oils, process oils, industrial grease, etc ). Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves. Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or fuel. For purposes of § 98.233, routing emissions from a dehydrator regenerator still vent or flash tank separator vent to a regenerator fire-box/fire tubes does not meet the definition of vapor recovery system. Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pipelines or consumers with natural gas. Vegetable oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel. Ventilation hole or shaft means a vent hole, shaft, mine portal, adit or other mine entrance or exits employed at an underground coal mine to serve as the outlet or conduit to move air from the ventilation system out of the mine. Ventilation system means a system that is used to control the concentration of methane and other gases within mine working areas through mine ventilation, rather than a mine degasification system. A ventilation system consists of fans that move air through the mine workings to dilute methane concentrations. Volatile solids are the organic material in livestock manure and consist of both biodegradable and non-biodegradable fractions. Waelz kiln means an inclined rotary kiln in which zinc-containing materials are charged together with a carbon reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal). Waxes means a solid or semi-solid material at 77 °F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 °F and a maximum oil content of 50 weight percent. Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphere. This process may also include high-rate flowback of injected gas, water, oil, and proppant used to fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum and natural gas wells to try to increase production. This process also includes high-rate flowback of injected gas, water, oil, and proppant used to re-fracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. Wellhead means the piping, casing, tubing and connected valves protruding above the earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and portable, located on the improved land area ( i.e. well pad) surrounding one or multiple wellheads. Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleable natural gas delivered from transmission and distribution pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas.” Wood residuals means materials recovered from three principal sources: Municipal solid waste (MSW); construction and demolition debris; and primary timber processing. Wood residuals recovered from MSW include wooden furniture, cabinets, pallets and containers, scrap lumber (from sources other than construction and demolition activities), and urban tree and landscape residues. Wood residuals from construction and demolition debris originate from the construction, repair, remodeling and demolition of houses and non-residential structures. Wood residuals from primary timber processing include bark, sawmill slabs and edgings, sawdust, and peeler log cores. Other sources of wood residuals include, but are not limited to, railroad ties, telephone and utility poles, pier and dock timbers, wastewater process sludge from paper mills, trim, sander dust, and sawdust from wood products manufacturing (including resinated wood product residuals), and logging residues. Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993. Working capacity , for the purposes of subpart TT of this part, means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 percent filled and/or 100 percent emptied for each load. You means an owner or operator subject to Part 98. Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving the reduction and volatization of zinc-bearing feed materials charged to a furnace." 40:40:23.0.1.1.2.1.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.7 What standardized methods are incorporated by reference into this part?,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 39759, July 12, 2010; 75 FR 66458, Oct. 28, 2010; 75 FR 74488, Nov. 30, 2010; 75 FR 74816, Dec. 1, 2010; 75 FR 79138, Dec. 17, 2010; 78 FR 68202, Nov. 13, 2013; 78 FR 71948, Nov. 29, 2013; 81 FR 89250, Dec. 9, 2016; 89 FR 31892, Apr. 25, 2024; 89 FR 42220, May 14, 2024]","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 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/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 fr.inspection@nara.gov. The material may be obtained from the following sources: (a) [Reserved] (b) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-5151, http://www.asminternational.org. (1) ASM CS-104 UNS No. G10460—Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content), incorporation by reference (IBR) approved for § 98.174(b). (2) [Reserved] (c) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org. (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for § 98.124(m)(1), § 98.324(e), § 98.354(d), § 98.354(h), § 98.344(c) and § 98.364(e). (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for § 98.124(m)(2), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e). (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved for § 98.124(m)(3) and § 98.354(d). (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for § 98.124(m)(4), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e). (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for § 98.124(m)(5), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e). (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for § 98.124(m)(6). (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for § 98.124(m)(7), § 98.324(e), § 98.344(c), and § 98.354(h). (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for § 98.124(m)(8), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e). (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flow Meters, IBR approved for § 98.354(d). (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e). (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 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 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 (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 D6348-12 (Reapproved 2020) Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, Approved December 1, 2020, IBR approved for § 98.234(i). (37) 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). (38) ASTM D6609-08, Standard Guide for Part-Stream Sampling of Coal; IBR approved for § 98.164(b). (39) ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels; IBR approved for § 98.6. (40) 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). (41) ASTM D6883-04, Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles; IBR approved for § 98.164(b). (42) 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). (43) ASTM D7430-08ae1, Standard Practice for Mechanical Sampling of Coal; IBR approved for § 98.164(b). (44) 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). (45) ASTM D7633-10, Standard Test Method for Carbon Black—Carbon Content, approved May 15, 2010; IBR approved for § 98.244(b). (46) ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate); IBR approved for § 98.294(a) and (b). (47) 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). (48) 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). (49) 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). (50) 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). (51) 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 (CO 2 -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. This standard is also available from ISO as ISO 27916:2019(E). (2) [Reserved] (f) The following material is available for purchase from the Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918) 493-3872, http://www.gasprocessors.com. (1) [Reserved] (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for § 98.164(b), § 98.254(d), § 98.344(b), and § 98.354(g). (g) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11, http://www.iso.org/iso/home.htm. (1) ISO 3170: Petroleum liquids—Manual sampling—Third Edition 2004-02-01, IBR approved for § 98.164(b). (2) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition 1988-12-01, IBR approved for § 98.164(b). (3) [Reserved] (4) ISO/CSAPR 15349-1: 1998, Unalloyed steel—Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15)—First Edition, IBR approved for § 98.174(b). (5) ISO/CSAPR 15349-3: 1998, Unalloyed steel—Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15)—First Edition, IBR approved for § 98.174(b). (h) The following material is available for purchase from the National Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org. (1) CO 2 Emissions Calculation Protocol for the Lime Industry—English Units Version, February 5, 2008 Revision—National Lime Association, incorporation by reference (IBR) approved for § 98.194(c) and § 98.194(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). (j) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org. (1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.276(c) and § 98.277(d). (2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.274(b). (k) The following material is available for purchase from Standard Methods, at http://www.standardmethods.org , (877) 574-1233; or, through a joint publication agreement from the American Public Health Association (APHA), P.O. Box 933019, Atlanta, GA 31193-3019, (888) 320-APHA (2742), http://www.apha.org/publications/pubscontact/. (1) Method 2540G Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, IBR approved for § 98.464(b). (2) [Reserved] (l) The following material is available from the U.S. Department of Labor, Mine Safety and Health Administration, 1100 Wilson Boulevard, 21st Floor, Arlington, VA 22209-3939, (202) 693-9400, http://www.msha.gov. (1) PH16-V-1, Coal Mine Safety and Health General Inspection Procedures Handbook, June 2016, IBR approved for § 98.324(b). (2) [Reserved] (m) The following material is available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov. (1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 305-X-04-001, July 2004, http://www.epa.gov/compliance/monitoring/programs/cwa/npdes.html , IBR approved for § 98.354(c). (2) U.S. EPA NPDES Permit Writers' Manual, Section 7.1.3, Sample Collection Methods, EPA 833-B-96-003, December 1996, http://www.epa.gov/npdes/pubs/owm0243.pdf , IBR approved for § 98.354(c). (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/2016-02/documents/dre_protocol.pdf. ) (4) Emissions Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final, http://www.epa.gov/ttnchie1/eiip/techreport/volume02/index.html , IBR approved for § 98.123(c)(1)(i)(A). (5) Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, November 1995 (EPA-453/R-95-017), http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf , IBR approved for § 98.123(d)(1)(i), § 98.123(d)(1)(ii), § 98.123(d)(1)(iii), and § 98.124(f)(2). (6) Tracer Gas Protocol for the Determination of Volumetric Flow Rate Through the Ring Pipe of the Xact Multi-Metals Monitoring System, also known as Other Test Method 24 (Tracer Gas Protocol), Eli Lilly and Company Tippecanoe Laboratories, September 2006, http://www.epa.gov/ttn/emc/prelim/otm24.pdf , IBR approved for § 98.124(e)(1)(ii). (7) Approved Alternative Method 012: An Alternate Procedure for Stack Gas Volumetric Flow Rate Determination (Tracer Gas) (ALT-012), U.S. Environmental Protection Agency Emission Measurement Center, May 23, 1994, http://www.epa.gov/ttn/emc/approalt/alt-012.pdf , IBR approved for § 98.124(e)(1)(ii). (8) Protocol for Measurement of Tetrafluoromethane (CF 4 ) and Hexafluoroethane (C 2 F 6 ) Emissions from Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf , IBR approved for § 98.64(a). (9) AP 42, Section 5.2, Transportation and Marketing of Petroleum Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf ; in Chapter 5, Petroleum Industry, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for § 98.253(n). (10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf ; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii). (11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii). (12) Method 8021B, Aromatic and Halogenated Volatiles By Gas Chromatography Using Photoionization and/or Electrolytic Conductivity Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf ; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii). (13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf ; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii). (14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf ; in Chapter 7, Liquid Storage Tanks, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for § 98.253(m)(1) and § 98.256(o)(2)(i). (15) Other Test Method 52 (OTM-52), Method for Determination of Combustion Efficiency from Enclosed Combustors Located at Oil and Gas Production Facilities, dated September 26, 2023, https://www.epa.gov/emc/emc-other-test-methods , IBR approved for § 98.233(n). (n)-(o) [Reserved] (p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-2555, http://www.aapg.org. (1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR approved for § 98.238. (2) Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for § 98.238. (q) The following material is available from the Energy Information Administration (EIA), 1000 Independence Ave., SW., Washington, DC 20585, (202) 586-8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.pdf. (1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for § 98.238. (2) [Reserved]" 40:40:23.0.1.1.2.1.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.8 What are the compliance and enforcement provisions of this part?,EPA,,,,"Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. 7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation." 40:40:23.0.1.1.2.1.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,A,Subpart A—General Provision,,§ 98.9 Addresses.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 76 FR 73900, Nov. 29, 2011]","All requests, notifications, and communications to the Administrator pursuant to this part must be submitted electronically and in a format as specified by the Administrator. For example, any requests, notifications and communications that can be submitted through the electronic GHG reporting tool, must be submitted through that tool. If not specified, requests, notifications or communications shall be submitted to the following address: (a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460. (b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005." 40:40:23.0.1.1.2.11.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.110 Definition of the source category.,EPA,,,,"The ferroalloy production source category consists of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal." 40:40:23.0.1.1.2.11.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.111 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either § 98.2(a)(1) or (2). 40:40:23.0.1.1.2.11.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.112 GHGs to report.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010]","You must report: (a) Process CO 2 emissions from each electric arc furnace (EAF) used for the production of any ferroalloy listed in § 98.110, and process CH 4 emissions from each EAF that is used for the production of any ferroalloy listed in Table K-1 to subpart K. (b) CO 2 , CH 4 , and N 2 O 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 (General Stationary Fuel Combustion Sources)." 40:40:23.0.1.1.2.11.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.113 Calculating GHG emissions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 78 FR 71954, Nov. 29, 2013]","You must calculate and report the annual process CO 2 emissions from each EAF not subject to paragraph (c) of this section using the procedures in either paragraph (a) or (b) of this section. For each EAF also subject to annual process CH 4 emissions reporting, you must also calculate and report the annual process CH 4 emissions from the EAF using the procedures in paragraph (d) of this section. (a) Calculate and report under this subpart the process CO 2 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 (General Stationary Fuel Combustion Sources). (b) Calculate and report under this subpart the annual process CO 2 emissions using the procedure in either paragraph (b)(1) or (b)(2) of this section. (1) Calculate and report under this subpart the annual process CO 2 emissions from EAFs by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in § 98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). (2) Calculate and report under this subpart the annual process CO 2 emissions from the EAFs using the carbon mass balance procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section. (i) For each EAF, determine the annual mass of carbon in each carbon-containing input and output material for the EAF and estimate annual process CO 2 emissions from the EAF using Equation K-1 of this section. 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 K-1 of this section. Where: E CO2 = Annual process CO 2 emissions from an individual EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. M reducing agent i = Annual mass of reducing agent i fed, charged, or otherwise introduced into the EAF (tons). C reducing agent i = Carbon content in reducing agent i (percent by weight, expressed as a decimal fraction). M electrode m = Annual mass of carbon electrode m consumed in the EAF (tons). C electrode m = Carbon content of the carbon electrode m (percent by weight, expressed as a decimal fraction). M ore h = Annual mass of ore h charged to the EAF (tons). C ore h = Carbon content in ore h (percent by weight, expressed as a decimal fraction). M flux j = Annual mass of flux material j fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons). C flux j = Carbon content in flux material j (percent by weight, expressed as a decimal fraction). M product k = Annual mass of alloy product k tapped from EAF (tons). C product k = Carbon content in alloy product k. (percent by weight, expressed as a decimal fraction). M non-product outgoing l = Annual mass of non-product outgoing material l removed from EAF (tons). C non-product outgoing l = Carbon content in non-product outgoing material l (percent by weight, expressed as a decimal fraction). Where: E CO2 = Annual process CO 2 emissions from an individual EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. M reducing agent i = Annual mass of reducing agent i fed, charged, or otherwise introduced into the EAF (tons). C reducing agent i = Carbon content in reducing agent i (percent by weight, expressed as a decimal fraction). M electrode m = Annual mass of carbon electrode m consumed in the EAF (tons). C electrode m = Carbon content of the carbon electrode m (percent by weight, expressed as a decimal fraction). M ore h = Annual mass of ore h charged to the EAF (tons). C ore h = Carbon content in ore h (percent by weight, expressed as a decimal fraction). M flux j = Annual mass of flux material j fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons). C flux j = Carbon content in flux material j (percent by weight, expressed as a decimal fraction). M product k = Annual mass of alloy product k tapped from EAF (tons). C product k = Carbon content in alloy product k. (percent by weight, expressed as a decimal fraction). M non-product outgoing l = Annual mass of non-product outgoing material l removed from EAF (tons). C non-product outgoing l = Carbon content in non-product outgoing material l (percent by weight, expressed as a decimal fraction). (ii) Determine the combined annual process CO 2 emissions from the EAFs at your facility using Equation K-2 of this section. Where: CO 2 = Annual process CO 2 emissions from EAFs at facility used for the production of any ferroalloy listed in § 98.110 (metric tons). E CO2 k = Annual process CO 2 emissions calculated from EAF k calculated using Equation K-1 of this section (metric tons). k = Total number of EAFs at facility used for the production of any ferroalloy listed in § 98.110. Where: CO 2 = Annual process CO 2 emissions from EAFs at facility used for the production of any ferroalloy listed in § 98.110 (metric tons). E CO2 k = Annual process CO 2 emissions calculated from EAF k calculated using Equation K-1 of this section (metric tons). k = Total number of EAFs at facility used for the production of any ferroalloy listed in § 98.110. (c) If GHG emissions from an EAF are vented through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. 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. (d) For the EAFs at your facility used for the production of any ferroalloy listed in Table K-1 of this subpart, you must calculate and report the annual CH 4 emissions using the procedure specified in paragraphs (d)(1) and (2) of this section. (1) For each EAF, determine the annual CH 4 emissions using Equation K-3 of this section. Where: E CH4 = Annual process CH 4 emissions from an individual EAF (metric tons). M product i = Annual mass of alloy product i produced in the EAF (tons). 2/2205 = Conversion factor to convert kg CH 4 /ton of product to metric tons CH 4 . EF product i = CH 4 emission factor for alloy product i from Table K-1 in this subpart (kg of CH 4 emissions per metric ton of alloy product i ). Where: E CH4 = Annual process CH 4 emissions from an individual EAF (metric tons). M product i = Annual mass of alloy product i produced in the EAF (tons). 2/2205 = Conversion factor to convert kg CH 4 /ton of product to metric tons CH 4 . EF product i = CH 4 emission factor for alloy product i from Table K-1 in this subpart (kg of CH 4 emissions per metric ton of alloy product i ). (2) Determine the combined process CH 4 emissions from the EAFs at your facility using Equation K-4 of this section: Where: CH 4 = Annual process CH 4 emissions from EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart (metric tons). E CH4 j = Annual process CH 4 emissions from EAF j calculated using Equation K-3 of this section (metric tons). j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart. Where: CH 4 = Annual process CH 4 emissions from EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart (metric tons). E CH4 j = Annual process CH 4 emissions from EAF j calculated using Equation K-3 of this section (metric tons). j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart." 40:40:23.0.1.1.2.11.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.114 Monitoring and QA/QC requirements.,EPA,,,,"If you determine annual process CO 2 emissions using the carbon mass balance procedure in § 98.113(b)(2), 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 CO 2 emissions using Equation K-1 of this subpart 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 (b)(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) through (b)(2)(iii) of this section, as applicable. (i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7) for analysis of metal ore and alloy product. (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes. (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials such as limestone or dolomite." 40:40:23.0.1.1.2.11.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.115 Procedures for estimating missing data.,EPA,,,,"A complete record of all measured parameters used in the GHG emissions calculations in § 98.113 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall 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 CO 2 emissions for the EAFs at your facility using the carbon mass balance procedure in § 98.113(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 § 98.114(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 on all available process data or data used for accounting purposes, such as purchase records. (c) If you are required to calculate CH 4 emissions for an EAF at your facility as specified in § 98.113(d), the estimate is based an annual quantity of certain alloy products, so 100 percent data availability is required." 40:40:23.0.1.1.2.11.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.116 Data reporting requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 78 FR 71954, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014]","In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable: (a) Annual facility ferroalloy product production capacity (tons). (b) If a CEMS is used to measure CO 2 emissions, report the annual production for each ferroalloy product identified in § 98.110, from each EAF (tons). (c) Total number of EAFs at facility used for production of ferroalloy products. (d) If a CEMS is used to measure CO 2 emissions, then you must report under this subpart the relevant information required by § 98.36 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (d)(1) through (d)(3) of this section. (1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy product identified in § 98.110. (2) Annual process CH 4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons). (3) Identification number of each EAF. (e) If a CEMS is not used to measure CO 2 process emissions, and the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in § 98.113(b), then you must report the following information specified in paragraphs (e)(1) through (e)(7) of this section. (1) Annual process CO 2 emissions (in metric tons) from each EAF used for the production of any ferroalloy identified in § 98.110 (metric tons). (2) Annual process CH 4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart. (3) Identification number for each material. (4)-(5) [Reserved] (6) List the method used for the determination of carbon content for each material included for the calculation of annual process CO 2 emissions for each EAF ( e.g., supplier provided information, analyses of representative samples you collected). (7) If you use the missing data procedures in § 98.115(b), you must report how monthly mass of carbon-containing inputs and outputs with missing data was determined and the number of months the missing data procedures were used." 40:40:23.0.1.1.2.11.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.117 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63785, Oct. 24, 2014]","In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each EAF, as applicable. (a) If a CEMS is used to measure CO 2 emissions according to the requirements in § 98.113(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 (a)(3) of this section. (1) Monthly EAF production quantity for each ferroalloy product (tons). (2) Number of EAF operating hours each month. (3) Number of EAF operating hours in a calendar year. (b) If the carbon mass balance procedure is used to determine CO 2 emissions according to the requirements in § 98.113(b)(2), then you must retain records for the information specified in paragraphs (b)(1) through (b)(5) of this section. (1) Monthly EAF production quantity for each ferroalloy product (tons). (2) Number of EAF operating hours each month. (3) Number of EAF operating hours in a calendar year. (4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO 2 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 CO 2 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 EAF, including documentation of specific input or output materials excluded from Equation K-1 of this subpart 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 an EAF 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) If you are required to calculate CH 4 emissions for the EAF as specified in § 98.113(d), you must maintain records of the total amount of each alloy product produced for the specified reporting period, and the appropriate alloy-product specific emission factor used to calculate the CH 4 emissions. (e) Verification software records. 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 (13) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (13) of this section. (1) Carbon content in reducing agent (percent by weight, expressed as a decimal fraction) (Equation K-1 of § 98.113). (2) Annual mass of reducing agent fed, charged, or otherwise introduced into the EAF (tons) (Equation K-1). (3) Carbon content of carbon electrode (percent by weight, expressed as a decimal fraction) (Equation K-1). (4) Annual mass of carbon electrode consumed in the EAF (tons) (Equation K-1). (5) Carbon content in ore (percent by weight, expressed as a decimal fraction) (Equation K-1). (6) Annual mass of ore charged to the EAF (tons) (Equation K-1). (7) Carbon content in flux material (percent by weight, expressed as a decimal fraction) (Equation K-1). (8) Annual mass of flux material fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons) (Equation K-1). (9) Carbon content in alloy product (percent by weight, expressed as a decimal fraction) (Equation K-1). (10) Annual mass of alloy product produced/tapped in the EAF (tons) (Equation K-1). (11) Carbon content in non-product outgoing material (percent by weight, expressed as a decimal fraction) (Equation K-1). (12) Annual mass of non-product outgoing material removed from EAF (tons) (Equation K-1). (13) CH 4 emission factor selected from Table K-1 of this subpart for each product (kg of CH 4 emissions/metric ton of alloy product) (Equation K-3 of § 98.113)." 40:40:23.0.1.1.2.11.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,K,Subpart K—Ferroalloy Production,,§ 98.118 Definitions.,EPA,,,,All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.12.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.120 Definition of the source category.,EPA,,,,"(a) The fluorinated gas production source category consists of processes that produce a fluorinated gas from any raw material or feedstock chemical, except for processes that generate HFC-23 during the production of HCFC-22. (b) To produce a fluorinated gas means to manufacture a fluorinated gas from any raw material or feedstock chemical. Producing a fluorinated gas includes producing a fluorinated GHG as defined at § 98.410(b). Producing a fluorinated gas also includes the manufacture of a chlorofluorocarbon (CFC) or hydrochlorofluorocarbon (HCFC) from any raw material or feedstock chemical, including manufacture of a CFC or HCFC as an isolated intermediate for use in a process that will result in the transformation of the CFC or HCFC either at or outside of the production facility. Producing a fluorinated gas does not include the reuse or recycling of a fluorinated gas, the creation of HFC-23 during the production of HCFC-22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement in § 98.414(a)." 40:40:23.0.1.1.2.12.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.121 Reporting threshold.,EPA,,,,"You must report GHG emissions under this subpart if your facility contains a fluorinated gas production process that generates or emits fluorinated GHG and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). To calculate GHG emissions for comparison to the 25,000 metric ton CO 2 e per year emission threshold in § 98.2(a)(2), calculate process emissions from fluorinated gas production using uncontrolled GHG emissions." 40:40:23.0.1.1.2.12.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.122 GHGs to report.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014","(a) You must report CO 2 , CH 4 , and N 2 O combustion emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (b) You must report under subpart O of this part (HCFC-22 Production and HFC-23 Destruction) the emissions of HFC-23 from HCFC-22 production processes and HFC-23 destruction processes. Do not report the generation and emissions of HFC-23 from HCFC-22 production under this subpart. (c) Emissions from production and transformation processes, process level. You must report, for each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group (in metric tons CO 2 e) emitted from: (1) Each fluorinated gas production process. (2) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where no fluorinated GHG reactant is produced at another facility. (3) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where one or more fluorinated GHG reactants are produced at another facility. (d) Emissions from production and transformation processes, facility level, multiple products. If your facility produces more than one fluorinated gas product, you must report the emissions (in metric tons) from production and transformation processes, totaled across the facility as a whole, of each fluorinated GHG that is emitted in quantities of 1,000 metric tons of CO 2 e or more from production or transformation processes, totaled across the facility as a whole. Aggregate and report emissions of all other fluorinated GHGs from production and transformation processes by fluorinated GHG group for the facility as a whole, in metric tons of CO 2 e. (e) Emissions from production and transformation processes, facility level, one product only. If your facility produces only one fluorinated gas product, aggregate and report the GWP-weighted emissions from production and transformation processes of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons CO 2 e, with the following exception: Where emissions consist of a major fluorinated GHG constituent of a fluorinated gas product, and the product is sold or transferred to another person, report the total mass of each fluorinated GHG that is emitted from production and transformation processes and that is a major fluorinated GHG constituent of the product (in metric tons). (f) Emissions from destruction processes and venting of containers. You must report the total mass of each fluorinated GHG emitted (in metric tons) from: (1) Each fluorinated gas destruction process that is not part of a fluorinated gas production process or a fluorinated gas transformation process and all such fluorinated gas destruction processes combined. (2) Venting of residual fluorinated GHGs from containers returned from the field." 40:40:23.0.1.1.2.12.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.123 Calculating GHG emissions.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014]","For fluorinated gas production and transformation processes, you must calculate the fluorinated GHG emissions from each process using the emission factor or emission calculation factor method specified in paragraphs (c), (d), and (e) of this section, as appropriate. For destruction processes that destroy fluorinated GHGs that were previously “produced” as defined at § 98.410(b), you must calculate emissions using the procedures in paragraph (f) of this section. For venting of residual gas from containers ( e.g., cylinder heels), you must calculate emissions using the procedures in paragraph (g) of this section. (a) [Reserved] (b) Mass balance method. The mass balance method was available for reporting years 2011, 2012, 2013, and 2014 only. See paragraph 1 of appendix A of this subpart for the former mass balance method. (c) Emission factor and emission calculation factor methods. To use the method in this paragraph for batch processes, you must comply with either paragraph (c)(3) of this section (Emission Factor approach) or paragraph (c)(4) of this section (Emission Calculation Factor approach). To use the method in this paragraph for continuous processes, you must first make a preliminary estimate of the emissions from each individual continuous process vent under paragraph (c)(1) of this section. If your continuous process operates under different conditions as part of normal operations, you must also define the different operating scenarios and make a preliminary estimate of the emissions from the vent for each operating scenario. Then, compare the preliminary estimate for each continuous process vent (summed across operating scenarios) to the criteria in paragraph (c)(2) of this section to determine whether the process vent meets the criteria for using the emission factor method described in paragraph (c)(3) of this section or whether the process vent meets the criteria for using the emission calculation factor method described in paragraph (c)(4) of this section. For continuous process vents that meet the criteria for using the emission factor method described in paragraph (c)(3) of this section and that have more than one operating scenario, compare the preliminary estimate for each operating scenario to the criteria in (c)(3)(ii) to determine whether an emission factor must be developed for that operating scenario. (1) Preliminary estimate of emissions by process vent. You must estimate the annual CO 2 e emissions of fluorinated GHGs for each process vent within each operating scenario of a continuous process using the approaches specified in paragraph (c)(1)(i) or (c)(1)(ii) of this section, accounting for any destruction as specified in paragraph (c)(1)(iii) of this section. You must determine emissions of fluorinated GHGs by process vent by using measurements, by using calculations based on chemical engineering principles and chemical property data, or by conducting an engineering assessment. You may use previous measurements, calculations, and assessments if they represent current process operating conditions or process operating conditions that would result in higher fluorinated GHG emissions than the current operating conditions and if they were performed in accordance with paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, as applicable. You must document all data, assumptions, and procedures used in the calculations or engineering assessment and keep a record of the emissions determination as required by § 98.127(a). (i) Engineering calculations. For process vent emission calculations, you may use any of paragraphs (c)(1)(i)(A), (c)(1)(i)(B), or (c)(1)(i)(C) of this section. (A) U.S. Environmental Protection Agency, Emission Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final (incorporated by reference, see § 98.7). (B) You may determine the fluorinated GHG emissions from any process vent within the process using the procedures specified in § 63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter, except as specified in paragraphs (c)(1)(i)(B)( 1 ) through (c)(1)(i)(B)( 4 ) of this section. For the purposes of this subpart, use of the term “HAP” in § 63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter means “fluorinated GHG”. ( 1 ) To calculate emissions caused by the heating of a vessel without a process condenser to a temperature lower than the boiling point, you must use the procedures in § 63.1257(d)(2)(i)(C)( 3 ) of this chapter. ( 2 ) To calculate emissions from depressurization of a vessel without a process condenser, you must use the procedures in § 63.1257(d)(2)(i)(D)( 10 ) of this chapter. ( 3 ) To calculate emissions from vacuum systems, the terms used in Equation 33 to § 63.1257(d)(2)(i)(E) of this chapter are defined as follows: ( i ) P system = Absolute pressure of the receiving vessel. ( ii ) P i = Partial pressure of the fluorinated GHG determined at the exit temperature and exit pressure conditions of the condenser or at the conditions of the dedicated receiver. ( iii ) P j = Partial pressure of condensables (including fluorinated GHG) determined at the exit temperature and exit pressure conditions of the condenser or at the conditions of the dedicated receiver. ( iv ) MW Fluorinated GHG = Molecular weight of the fluorinated GHG determined at the exit temperature and exit pressure conditions of the condenser or at the conditions of the dedicated receiver. ( 4 ) To calculate emissions when a vessel is equipped with a process condenser or a control condenser, you must use the procedures in § 63.1257(d)(3)(i)(B) of this chapter, except as follows: ( i ) You must determine the flowrate of gas (or volume of gas), partial pressures of condensables, temperature (T), and fluorinated GHG molecular weight (MW Fluorinated GHG ) at the exit temperature and exit pressure conditions of the condenser or at the conditions of the dedicated receiver. ( ii ) You must assume that all of the components contained in the condenser exit vent stream are in equilibrium with the same components in the exit condensate stream (except for noncondensables). ( iii ) You must perform a material balance for each component, if the condensate receiver composition is not known. ( iv ) For the emissions from gas evolution, the term for time, t, must be used in Equation 12 to § 63.1257(d)(2)(i)(B) of this chapter. ( v ) Emissions from empty vessel purging must be calculated using Equation 36 to § 63.1257(d)(2)(i)(H) of this chapter and the exit temperature and exit pressure conditions of the condenser or the conditions of the dedicated receiver. (C) Commercial software products that follow chemical engineering principles (e.g., including the calculation methodologies in paragraphs (c)(1)(i)(A) and (c)(1)(i)(B) of this section). (ii) Engineering assessments. For process vent emissions determinations, you may conduct an engineering assessment to calculate uncontrolled emissions. An engineering assessment includes, but is not limited to, the following: (A) Previous test results, provided the tests are representative of current operating practices of the process. (B) Bench-scale or pilot-scale test data representative of the process operating conditions. (C) Maximum flow rate, fluorinated GHG emission rate, concentration, or other relevant parameters specified or implied within a permit limit applicable to the process vent. (D) Design analysis based on chemical engineering principles, measureable process parameters, or physical or chemical laws or properties. (iii) Impact of destruction for the preliminary estimate. If the process vent is vented to a destruction device, you may reflect the impact of the destruction device on emissions. In your emissions estimate, account for the following: (A) The destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream for periods when the process vent is vented to the destruction device. (B) Any periods when the process vent is not vented to the destruction device. (iv) Use of typical recent values. In the calculations in paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, the values used for the expected process activity and for the expected fraction of that activity whose emissions will be vented to the properly functioning destruction device must be based on either typical recent values for the process or values that would overestimate emissions from the process, unless there is a compelling reason to adopt a different value (e.g., installation of a destruction device for a previously uncontrolled process). If there is such a reason, it must be documented in the GHG Monitoring Plan. (v) GWPs. To convert the fluorinated GHG emissions to CO 2 e, use Equation A-1 of § 98.2. (vi) [Reserved] (2) Method selection for continuous process vents. (i) If the calculations under paragraph (c)(1) of this section, as well as any subsequent measurements and calculations under this subpart, indicate that the continuous process vent has fluorinated GHG emissions of less than 10,000 metric ton CO 2 e per year, summed across all operating scenarios, then you may comply with either paragraph (c)(3) of this section (Emission Factor approach) or paragraph (c)(4) of this section (Emission Calculation Factor approach). (ii) If the continuous process vent does not meet the criteria in paragraph (c)(2)(i) of this section, then you must comply with the emission factor method specified in paragraph (c)(3) (Emission Factor approach) of this section. (A) You must conduct emission testing for process-vent-specific emission factor development before the destruction device unless the calculations you performed under paragraph (c)(1)(iii) of this section indicate that the uncontrolled fluorinated GHG emissions that occur during periods when the process vent is not vented to the properly functioning destruction device are less than 10,000 metric tons CO 2 e per year. In this case, you may conduct emission testing after the destruction device to develop a process-vent-specific emission factor. If you do so, you must develop and apply an emission calculation factor under paragraph (c)(4) to estimate emissions during any periods when the process vent is not vented to the properly functioning destruction device. (B) Regardless of the level of uncontrolled emissions, the emission testing for process-vent-specific emission factor development may be conducted on the outlet side of a wet scrubber in place for acid gas reduction, if one is in place, as long as there is no appreciable reduction in the fluorinated GHG. (3) Process-vent-specific emission factor method. For each process vent, conduct an emission test and measure fluorinated GHG emissions from the process and measure the process activity, such as the feed rate, production rate, or other process activity rate, during the test as described in this paragraph (c)(3). Conduct the emission test according to the procedures in § 98.124. All emissions test data and procedures used in developing emission factors must be documented according to § 98.127. If more than one operating scenario applies to the process that contains the subject process vent, you must comply with either paragraph (3)(i) or paragraph (3)(ii) of this section. (i) Conduct a separate emissions test for operation under each operating scenario. (ii) Conduct an emissions test for the operating scenario that is expected to have the largest emissions in terms of CO 2 e (considering both activity levels and emission calculation factors) on an annual basis. Also conduct an emissions test for each additional operating scenario that is estimated to emit 10,000 metric tons CO 2 e or more annually from the vent and whose emission calculation factor differs by 15 percent or more from the emission calculation factor of the operating scenario that is expected to have the largest emissions (or of another operating scenario for which emission testing is performed), unless the difference between the operating scenarios is solely due to the application of a destruction device to emissions under one of the operating scenarios. For any other operating scenarios, adjust the process-vent specific emission factor developed for the operating scenario that is expected to have the largest emissions (or for another operating scenario for which emission testing is performed) using the approach in paragraph (c)(3)(viii) of this section. (iii) You must measure the process activity, such as the process feed rate, process production rate, or other process activity rate, as applicable, during the emission test and calculate the rate for the test period, in kg (or another appropriate metric) per hour. (iv) For continuous processes, you must calculate the hourly emission rate of each fluorinated GHG using Equation L-19 of this section and determine the hourly emission rate of each fluorinated GHG per process vent (and per operating scenario, as applicable) for the test run. Where: E ContPV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, during the emission test during test run r (kg/hr). C PV = Concentration of fluorinated GHG f during test run r of the emission test (ppmv). MW = Molecular weight of fluorinated GHG f (g/g-mole). Q PV = Flow rate of the process vent stream during test run r of the emission test (m 3 /min). SV = Standard molar volume of gas (0.0240 m 3 /g-mole at 68 °F and 1 atm). 1/10 3 = Conversion factor (1 kilogram/1,000 grams). 60/1 = Conversion factor (60 minutes/1 hour). Where: E ContPV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, during the emission test during test run r (kg/hr). C PV = Concentration of fluorinated GHG f during test run r of the emission test (ppmv). MW = Molecular weight of fluorinated GHG f (g/g-mole). Q PV = Flow rate of the process vent stream during test run r of the emission test (m 3 /min). SV = Standard molar volume of gas (0.0240 m 3 /g-mole at 68 °F and 1 atm). 1/10 3 = Conversion factor (1 kilogram/1,000 grams). 60/1 = Conversion factor (60 minutes/1 hour). (v) You must calculate a site-specific, process-vent-specific emission factor for each fluorinated GHG for each process vent and each operating scenario, in kg of fluorinated GHG per process activity rate (e.g., kg of feed or production), as applicable, using Equation L-20 of this section. For continuous processes, divide the hourly fluorinated GHG emission rate during the test by the hourly process activity rate during the test runs. Where: EF PV = Emission factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j (e.g., kg emitted/kg activity). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, during the emission test during test run r, for either continuous or batch (kg emitted/hr for continuous, kg emitted/batch for batch). Activity EmissionTest = Process feed, process production, or other process activity rate for process i, operating scenario j, during the emission test during test run r (e.g., kg product/hr). r = Number of test runs performed during the emission test. Where: EF PV = Emission factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j (e.g., kg emitted/kg activity). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, during the emission test during test run r, for either continuous or batch (kg emitted/hr for continuous, kg emitted/batch for batch). Activity EmissionTest = Process feed, process production, or other process activity rate for process i, operating scenario j, during the emission test during test run r (e.g., kg product/hr). r = Number of test runs performed during the emission test. (vi) If you conducted emissions testing after the destruction device, you must calculate the emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) using Equation L-21 of this section. You must also develop a process-vent-specific emission calculation factor based on paragraph (c)(4) of this section for the periods when the process vent is not venting to the destruction device. Where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year (kg). EF PV-C = Emission factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, based on testing after the destruction device (kg emitted/activity) (e.g., kg emitted/kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which emissions are vented to the properly functioning destruction device (i.e., controlled). ECF PV-U = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j during periods when the process vent is not vented to the properly functioning destruction device (kg emitted/activity) (e.g., kg emitted/kg product). Activity U = Total process feed, process production, or other process activity during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). Where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year (kg). EF PV-C = Emission factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, based on testing after the destruction device (kg emitted/activity) (e.g., kg emitted/kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which emissions are vented to the properly functioning destruction device (i.e., controlled). ECF PV-U = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j during periods when the process vent is not vented to the properly functioning destruction device (kg emitted/activity) (e.g., kg emitted/kg product). Activity U = Total process feed, process production, or other process activity during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). (vii) If you conducted emissions testing before the destruction device, apply the destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-22 of this section. You may apply the destruction efficiency only to the portion of the process activity during which emissions are vented to the properly functioning destruction device (i.e., controlled). where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). EF PV-U = Emission factor (uncontrolled) for fluorinated GHG f emitted from process vent v during process i, operating scenario j (kg emitted/kg product). Activity U = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is vented to the properly functioning destruction device (e.g., kg product). DE = Demonstrated destruction efficiency of the destruction device (weight fraction). where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). EF PV-U = Emission factor (uncontrolled) for fluorinated GHG f emitted from process vent v during process i, operating scenario j (kg emitted/kg product). Activity U = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is vented to the properly functioning destruction device (e.g., kg product). DE = Demonstrated destruction efficiency of the destruction device (weight fraction). (viii) Adjusted process-vent-specific emission factors for other operating scenarios. For process vents from processes with multiple operating scenarios, use Equation L-23 of this section to develop an adjusted process-vent-specific emission factor for each operating scenario from which the vent is estimated to emit less than 10,000 metric tons CO 2 e annually or whose emission calculation factor differs by less than 15 percent from the emission calculation factor of the operating scenario that is expected to have the largest emissions (or of another operating scenario for which emission testing is performed). where: EF PVadj = Adjusted process-vent-specific emission factor for an untested operating scenario. ECF UT = Emission calculation factor for the untested operating scenario developed under paragraph (c)(4) of this section. ECF T = Emission calculation for the tested operating scenario developed under paragraph (c)(4) of this section. EF PV = Process vent specific emission factor for the tested operating scenario. where: EF PVadj = Adjusted process-vent-specific emission factor for an untested operating scenario. ECF UT = Emission calculation factor for the untested operating scenario developed under paragraph (c)(4) of this section. ECF T = Emission calculation for the tested operating scenario developed under paragraph (c)(4) of this section. EF PV = Process vent specific emission factor for the tested operating scenario. (ix) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-24 of this section. where: E Pfi = Mass of fluorinated GHG f emitted from process vents for process i for the year (kg). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). v = Number of process vents in process i, operating scenario j. o = Number of operating scenarios for process i. where: E Pfi = Mass of fluorinated GHG f emitted from process vents for process i for the year (kg). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). v = Number of process vents in process i, operating scenario j. o = Number of operating scenarios for process i. (4) Process-vent-specific emission calculation factor method. For each process vent within an operating scenario, determine fluorinated GHG emissions by calculations and determine the process activity rate, such as the feed rate, production rate, or other process activity rate, associated with the emission rate. (i) You must calculate uncontrolled emissions of fluorinated GHG by individual process vent, E PV , by using measurements, by using calculations based on chemical engineering principles and chemical property data, or by conducting an engineering assessment. Use the procedures in paragraphs (c)(1)(i) or (ii) of this section, except paragraph (c)(1)(ii)(C) of this section. The procedures in paragraphs (c)(1)(i) and (ii) of this section may be applied either to batch process vents or to continuous process vents. The uncontrolled emissions must be based on a typical batch or production rate under a defined operating scenario. The process activity rate associated with the uncontrolled emissions must be determined. The methods, data, and assumptions used to estimate emissions for each operating scenario must be selected to yield a best estimate (expected value) of emissions rather than an over- or underestimate of emissions for that operating scenario. All data, assumptions, and procedures used in the calculations or engineering assessment must be documented according to § 98.127. (ii) You must calculate a site-specific, process-vent-specific emission calculation factor for each process vent, each operating scenario, and each fluorinated GHG, in kg of fluorinated GHG per activity rate (e.g., kg of feed or production) as applicable, using Equation L-25 of this section. where: ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (e.g., kg emitted/kg product). E PV = Average mass of fluorinated GHG f emitted, based on calculations, from process vent v from process i, operating scenario j, during the period or batch for which emissions were calculated, for either continuous or batch (kg emitted/hr for continuous, kg emitted/batch for batch). Activity Representative = Process feed, process production, or other process activity rate corresponding to average mass of emissions based on calculations (e.g., kg product/hr for continuous, kg product/batch for batch). where: ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (e.g., kg emitted/kg product). E PV = Average mass of fluorinated GHG f emitted, based on calculations, from process vent v from process i, operating scenario j, during the period or batch for which emissions were calculated, for either continuous or batch (kg emitted/hr for continuous, kg emitted/batch for batch). Activity Representative = Process feed, process production, or other process activity rate corresponding to average mass of emissions based on calculations (e.g., kg product/hr for continuous, kg product/batch for batch). (iii) You must calculate emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) for the year by multiplying the process-vent-specific emission calculation factor by the total process activity, as applicable, for the year, using Equation L-26 of this section. where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year (kg). ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (kg emitted/activity) (e.g., kg emitted/kg product). Activity = Process feed, process production, or other process activity for process i, operating scenario j, during the year. where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year (kg). ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (kg emitted/activity) (e.g., kg emitted/kg product). Activity = Process feed, process production, or other process activity for process i, operating scenario j, during the year. (iv) If the process vent is vented to a destruction device, apply the demonstrated destruction efficiency of the device to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-27 of this section. Apply the destruction efficiency only to the portion of the process activity that is vented to the properly functioning destruction device (i.e., controlled). where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year considering destruction efficiency (kg). ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (e.g., kg emitted/kg product). Activity U = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is vented to the properly functioning destruction device (e.g., kg product). DE = Demonstrated destruction efficiency of the destruction device (weight fraction). where: E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year considering destruction efficiency (kg). ECF PV = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, (e.g., kg emitted/kg product). Activity U = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is not vented to the properly functioning destruction device (e.g., kg product). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j, during the year for which the process vent is vented to the properly functioning destruction device (e.g., kg product). DE = Demonstrated destruction efficiency of the destruction device (weight fraction). (v) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-28 of this section. where: E Pfi = Mass of fluorinated GHG f emitted from process vents for process i for the year (kg). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). v = Number of process vents in process i, operating scenario j. o = Number of operating scenarios in process i. where: E Pfi = Mass of fluorinated GHG f emitted from process vents for process i for the year (kg). E PV = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, considering destruction efficiency (kg). v = Number of process vents in process i, operating scenario j. o = Number of operating scenarios in process i. (d) Calculate fluorinated GHG emissions for equipment leaks (EL). If you comply with paragraph (c) of this section, you must calculate the fluorinated GHG emissions from pieces of equipment associated with processes covered under this subpart and in fluorinated GHG service. If you conduct monitoring of equipment in fluorinated GHG service, monitoring must be conducted for those in light liquid and in gas and vapor service. If you conduct monitoring of equipment in fluorinated GHG service, you may exclude from monitoring each piece of equipment that is difficult-to-monitor, that is unsafe-to-monitor, that is insulated, or that is in heavy liquid service; you may exclude from monitoring each pump with dual mechanical seals, agitator with dual mechanical seals, pump with no external shaft, agitator with no external shaft; you may exclude from monitoring each pressure relief device in gas and vapor service with upstream rupture disk, each sampling connection system with closed-loop or closed-purge systems, and any pieces of equipment where leaks are routed through a closed vent system to a destruction device. You must estimate emissions using another approach for those pieces of equipment excluded from monitoring. Equipment that is in fluorinated GHG service for less than 300 hr/yr; equipment that is in vacuum service; pressure relief devices that are in light liquid service; and instrumentation systems are exempted from these requirements. (1) The emissions from equipment leaks must be calculated using any of the procedures in paragraphs (d)(1)(i), (d)(1)(ii), (d)(1)(iii), or (d)(1)(iv) of this section. (i) Use of Average Emission Factor Approach in EPA Protocol for Equipment Leak Emission Estimates. The emissions from equipment leaks may be calculated using the default Average Emission Factor Approach in EPA-453/R-95-017 (incorporated by reference, see § 98.7). (ii) Use of Other Approaches in EPA Protocol for Equipment Leak Emission Estimates in conjunction with EPA Method 21 at 40 CFR part 60, appendix A-7. The emissions from equipment leaks may be calculated using one of the following methods in EPA-453/R-95-017 (incorporated by reference, see § 98.7): The Screening Ranges Approach; the EPA Correlation Approach; or the Unit-Specific Correlation Approach. If you determine that EPA Method 21 at 40 CFR part 60, appendix A-7 is appropriate for monitoring a fluorinated GHG, and if you calibrate your instrument with a compound different from one or more of the fluorinated GHGs or surrogates to be measured, you must develop response factors for each fluorinated GHG or for each surrogate to be measured using EPA Method 21 at 40 CFR part 60, appendix A-7. For each fluorinated GHG or surrogate measured, the response factor must be less than 10. The response factor is the ratio of the known concentration of a fluorinated GHG or surrogate to the observed meter reading when measured using an instrument calibrated with the reference compound. (iii) Use of Other Approaches in EPA Protocol for Equipment Leak Emission Estimates in conjunction with site-specific leak monitoring methods. The emissions from equipment leaks may be calculated using one of the following methods in EPA-453/R-95-017 (incorporated by reference, see § 98.7): The Screening Ranges Approach; the EPA Correlation Approach; or the Unit-Specific Correlation Approach. You may develop a site-specific leak monitoring method appropriate for monitoring fluorinated GHGs or surrogates to use along with these three approaches. The site-specific leak monitoring method must meet the requirements in § 98.124(f)(1). (iv) Use of site-specific leak monitoring methods. The emissions from equipment leaks may be calculated using a site-specific leak monitoring method. The site-specific leak monitoring method must meet the requirements in § 98.124(f)(1). (2) You must collect information on the number of each type of equipment; the service of each piece of equipment (gas, light liquid, heavy liquid); the concentration of each fluorinated GHG in the stream; and the time period each piece of equipment was in service. Depending on which approach you follow, you may be required to collect information for equipment on the associated screening data concentrations for greater than or equal to 10,000 ppmv and associated screening data concentrations for less than 10,000 ppmv; associated actual screening data concentrations; or associated screening data and leak rate data (i.e., bagging) used to develop a unit-specific correlation. (3) Calculate and sum the emissions of each fluorinated GHG in metric tons per year for equipment pieces for each process, E ELf , annually. You must include and estimate emissions for types of equipment that are excluded from monitoring, including difficult-to-monitor, unsafe-to-monitor and insulated pieces of equipment, pieces of equipment in heavy liquid service, pumps with dual mechanical seals, agitators with dual mechanical seals, pumps with no external shaft, agitators with no external shaft, pressure relief devices in gas and vapor service with upstream rupture disk, sampling connection systems with closed-loop or closed purge systems, and pieces of equipment where leaks are routed through a closed vent system to a destruction device. (e) Calculate total fluorinated GHG emissions for each process and for production or transformation processes at the facility. (1) Estimate annually the total mass of each fluorinated GHG emitted from each process, including emissions from process vents in paragraphs (c)(3) and (c)(4) of this section, as appropriate, and from equipment leaks in paragraph (d), using Equation L-29 of this section. where: E i = Total mass of each fluorinated GHG f emitted from process i, annual basis (kg/year). E Pfi = Mass of fluorinated GHG f emitted from all process vents and all operating scenarios in process i, annually (kg/year, calculated in Equation L-24 or L-28 of this section, as appropriate). E ELfi = Mass of fluorinated GHG f emitted from equipment leaks for pieces of equipment for process i, annually (kg/year, calculated in paragraph (d)(3) of this section). where: E i = Total mass of each fluorinated GHG f emitted from process i, annual basis (kg/year). E Pfi = Mass of fluorinated GHG f emitted from all process vents and all operating scenarios in process i, annually (kg/year, calculated in Equation L-24 or L-28 of this section, as appropriate). E ELfi = Mass of fluorinated GHG f emitted from equipment leaks for pieces of equipment for process i, annually (kg/year, calculated in paragraph (d)(3) of this section). (2) Estimate annually the total mass of each fluorinated GHG emitted from each type of production or transformation process at the facility using Equation L-30 of this section. Develop separate totals for fluorinated gas production processes, transformation processes that transform fluorinated gases produced at the facility, and transformation processes that transform fluorinated gases produced at another facility. where: E = Total mass of each fluorinated GHG f emitted from all fluorinated gas production processes, all transformation processes that transform fluorinated gases produced at the facility, or all transformation processes that transform fluorinated gases produced at another facility, as appropriate (metric tons). E i = Total mass of each fluorinated GHG f emitted from each production or transformation process, annual basis (kg/year, calculated in Equation L-29 of this section). 0.001 = Conversion factor from kg to metric tons. z = Total number of fluorinated gas production processes, fluorinated gas transformation processes that transform fluorinated gases produced at the facility, or transformation processes that transform fluorinated gases produced at another facility, as appropriate. where: E = Total mass of each fluorinated GHG f emitted from all fluorinated gas production processes, all transformation processes that transform fluorinated gases produced at the facility, or all transformation processes that transform fluorinated gases produced at another facility, as appropriate (metric tons). E i = Total mass of each fluorinated GHG f emitted from each production or transformation process, annual basis (kg/year, calculated in Equation L-29 of this section). 0.001 = Conversion factor from kg to metric tons. z = Total number of fluorinated gas production processes, fluorinated gas transformation processes that transform fluorinated gases produced at the facility, or transformation processes that transform fluorinated gases produced at another facility, as appropriate. (f) Calculate fluorinated GHG emissions from destruction of fluorinated GHGs that were previously “produced”. Estimate annually the total mass of fluorinated GHGs emitted from destruction of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) using Equation L-31 of this section: where: E D = The mass of fluorinated GHGs emitted annually from destruction of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) (metric tons). RE D = The mass of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) and that are fed annually into the destruction device (metric tons). DE = Destruction efficiency of the destruction device (fraction). where: E D = The mass of fluorinated GHGs emitted annually from destruction of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) (metric tons). RE D = The mass of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) and that are fed annually into the destruction device (metric tons). DE = Destruction efficiency of the destruction device (fraction). (g) Emissions from venting of residual fluorinated GHGs in containers. If you vent residual fluorinated GHGs from containers, you must either measure the residual fluorinated GHGs vented from each container or develop a heel factor for each combination of fluorinated GHG, container size, and container type that you vent. You do not need to estimate de minimis emissions associated with good-faith attempts to recycle or recover residual fluorinated GHGs in or from containers. (1) Measuring contents of each container. If you weigh or otherwise measure the contents of each container before venting the residual fluorinated GHGs, use Equation L-32 of this section to calculate annual emissions of each fluorinated GHG from venting of residual fluorinated GHG from containers. Convert pressures to masses as directed in paragraph (g)(2)(ii) of this section. Where: E Cf = Total mass of each fluorinated GHG f emitted from the facility through venting of residual fluorinated GHG from containers, annual basis (metric tons/year). H Bfj = Mass of residual fluorinated GHG f in container j when received by facility (metric tons). H Efj = Mass of residual fluorinated GHG f in container j after evacuation by facility (metric tons). (Facility may equate to zero.) n = Number of vented containers for each fluorinated GHG f. Where: E Cf = Total mass of each fluorinated GHG f emitted from the facility through venting of residual fluorinated GHG from containers, annual basis (metric tons/year). H Bfj = Mass of residual fluorinated GHG f in container j when received by facility (metric tons). H Efj = Mass of residual fluorinated GHG f in container j after evacuation by facility (metric tons). (Facility may equate to zero.) n = Number of vented containers for each fluorinated GHG f. (2) Developing and applying heel factors. If you use heel factors to estimate emissions of residual fluorinated GHGs vented from containers, you must annually develop these factors based on representative samples of the containers received by your facility from fluorinated GHG users. (i) Sample size. For each combination of fluorinated GHG, container size, and container type that you vent, select a representative sample of containers that reflects the full range of quantities of residual gas returned in that container size and type. This sample must reflect the full range of the industries and a broad range of the customers that use and return the fluorinated GHG, container size, and container type. The minimum sample size for each combination of fluorinated GHG, container size, and container type must be 30, unless this is greater than the number of containers returned within that combination annually, in which case the contents of every container returned must be measured. (ii) Measurement of residual gas. The residual weight or pressure you use for paragraph (g)(1) of this section must be determined by monitoring the mass or the pressure of your cylinders/containers according to § 98.124(k). If you monitor the pressure, convert the pressure to mass using a form of the ideal gas law, as displayed in Equation L-33 of this section, with an appropriately selected Z value. Where: m R = Mass of residual gas in the container (metric ton). p = Absolute pressure of the gas (Pa). V = Volume of the gas (m 3 ). MW = Molecular weight of the fluorinated GHG f (g/gmole). Z = Compressibility factor. R = Gas constant (8.314 Pa m 3 /Kelvin mole). T = Absolute temperature (K). 10 6 = Conversion factor (10 6 g/metric ton). Where: m R = Mass of residual gas in the container (metric ton). p = Absolute pressure of the gas (Pa). V = Volume of the gas (m 3 ). MW = Molecular weight of the fluorinated GHG f (g/gmole). Z = Compressibility factor. R = Gas constant (8.314 Pa m 3 /Kelvin mole). T = Absolute temperature (K). 10 6 = Conversion factor (10 6 g/metric ton). (iii) Heel factor calculation. To determine the heel factor h fj for each combination of fluorinated GHG, container size, and container type, use paragraph (g)(1) of this section to calculate the total heel emissions for each sample selected under paragraph (g)(2)(i) of this section. Divide this total by the number of containers in the sample. Divide the result by the full capacity (the mass of the contents of a full container) of that combination of fluorinated GHG, container size, and container type. The heel factor is expressed as a fraction of the full capacity. (iv) Calculate annual emissions of each fluorinated GHG from venting of residual fluorinated GHG from containers using Equation L-34 of this section. Where: E Cf = Total mass of each fluorinated GHG f emitted from the facility through venting of residual fluorinated GHG from containers, annual basis (metric tons/year). h fj = Facility-wide gas-specific heel factor for fluorinated GHG f (fraction) and container size and type j, as determined in paragraph (g)(2)(iii) of this section. N fj = Number of containers of size and type j returned to the fluorinated gas production facility. F fj = Full capacity of containers of size and type j containing fluorinated GHG f (metric tons). n = Number of combinations of container sizes and types for fluorinated GHG f. Where: E Cf = Total mass of each fluorinated GHG f emitted from the facility through venting of residual fluorinated GHG from containers, annual basis (metric tons/year). h fj = Facility-wide gas-specific heel factor for fluorinated GHG f (fraction) and container size and type j, as determined in paragraph (g)(2)(iii) of this section. N fj = Number of containers of size and type j returned to the fluorinated gas production facility. F fj = Full capacity of containers of size and type j containing fluorinated GHG f (metric tons). n = Number of combinations of container sizes and types for fluorinated GHG f. (h) Effective destruction efficiency for each process. If you used the emission factor or emission calculation factor method to calculate emissions from the process, use Equation L-35 to calculate the effective destruction efficiency for the process, including each process vent: Where: DE Effective = Effective destruction efficiency for process i (fraction). E PVf = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, calculated in Equation L-21, L-22, L-26, or L-27 of this section (kg). GWP f = Global warming potential for each greenhouse gas from Table A-1 of subpart A of this part. ECF PV-Uf = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j during periods when the process vent is not vented to the properly functioning destruction device, as used in Equation L-21; or emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, as used in Equation L-26 or L-27 (kg emitted/activity) ( e.g., kg emitted/kg product), denoted as “ECF PV ” in those equations. EF PV-Uf = Emission factor (uncontrolled) for fluorinated GHG f emitted from process vent v during process i, operating scenario j, as used in Equation L-22 (kg emitted/activity) ( e.g., kg emitted/kg product), denoted as “EF PV-U ” in that equation. Activity U = Total process feed, process production, or other process activity for process i, operating scenario j during the year, for which the process vent is not vented to the properly functioning destruction device ( i.e., uncontrolled). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j during the year, for which emissions are vented to the properly functioning destruction device ( i.e., controlled). o = Number of operating scenarios for process i. v = Number of process vents in process i, operating scenario j. w = Number of fluorinated GHGs emitted from the process. Where: DE Effective = Effective destruction efficiency for process i (fraction). E PVf = Mass of fluorinated GHG f emitted from process vent v from process i, operating scenario j, for the year, calculated in Equation L-21, L-22, L-26, or L-27 of this section (kg). GWP f = Global warming potential for each greenhouse gas from Table A-1 of subpart A of this part. ECF PV-Uf = Emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j during periods when the process vent is not vented to the properly functioning destruction device, as used in Equation L-21; or emission calculation factor for fluorinated GHG f emitted from process vent v during process i, operating scenario j, as used in Equation L-26 or L-27 (kg emitted/activity) ( e.g., kg emitted/kg product), denoted as “ECF PV ” in those equations. EF PV-Uf = Emission factor (uncontrolled) for fluorinated GHG f emitted from process vent v during process i, operating scenario j, as used in Equation L-22 (kg emitted/activity) ( e.g., kg emitted/kg product), denoted as “EF PV-U ” in that equation. Activity U = Total process feed, process production, or other process activity for process i, operating scenario j during the year, for which the process vent is not vented to the properly functioning destruction device ( i.e., uncontrolled). Activity C = Total process feed, process production, or other process activity for process i, operating scenario j during the year, for which emissions are vented to the properly functioning destruction device ( i.e., controlled). o = Number of operating scenarios for process i. v = Number of process vents in process i, operating scenario j. w = Number of fluorinated GHGs emitted from the process." 40:40:23.0.1.1.2.12.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.124 Monitoring and QA/QC requirements.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73787, Dec. 11, 2014]","(a) Initial scoping speciation to identify fluorinated GHGs. You must conduct an initial scoping speciation to identify all fluorinated GHGs that may be generated from processes that are subject to this subpart and that have at least one process vent with uncontrolled emissions of 1.0 metric ton or more of fluorinated GHGs per year based on the preliminary estimate of emissions in § 98.123(c)(1). You are not required to quantify emissions under this initial scoping speciation. Only fluorinated GHG products and by-products that occur in greater than trace concentrations in at least one stream must be identified under this paragraph. (1) Procedure. To conduct the scoping speciation, select the stream(s) (including process streams or destroyed streams) or process vent(s) that would be expected to individually or collectively contain all of the fluorinated GHG by-products of the process at their maximum concentrations and sample and analyze the contents of these selected streams or process vents. For example, if fluorinated GHG by-products are separated into one low-boiling-point and one high-boiling-point stream, sample and analyze both of these streams. Alternatively, you may sample and analyze streams where fluorinated GHG by-products occur at less than their maximum concentrations, but you must ensure that the sensitivity of the analysis is sufficient to compensate for the expected difference in concentration. For example, if you sample and analyze streams where fluorinated GHG by-products are expected to occur at one half their maximum concentrations elsewhere in the process, you must ensure that the sensitivity of the analysis is sufficient to detect fluorinated GHG by-products that occur at concentrations of 0.05 percent or higher. You do not have to sample and analyze every stream or process vent, i.e., you do not have to sample and analyze a stream or process vent that contains only fluorinated GHGs that are contained in other streams or process vents that are being sampled and analyzed. Sampling and analysis must be conducted according to the procedures in paragraph (e) of this section. (2) Previous measurements. If you have conducted testing of streams (including process streams or destroyed streams) or process vents less than 10 years before December 31, 2010, and the testing meets the requirements in paragraph (a)(1) of this section, you may use the previous testing to satisfy this requirement. (b) Mass balance monitoring. Mass balance monitoring was available for reporting years 2011, 2012, 2013, and 2014 only. See paragraph 2 of Appendix A of this subpart for the former mass balance method. (c) Emission factor testing. If you determine fluorinated GHG emissions using the site-specific process-vent-specific emission factor, you must meet the requirements in paragraphs (c)(1) through (c)(8) of this section. (1) Process vent testing. Conduct an emissions test that is based on representative performance of the process or operating scenario(s) of the process, as applicable. For process vents for which you performed an initial scoping speciation, include in the emission test any fluorinated GHG that was identified in the initial scoping speciation. For process vents for which you did not perform an initial scoping speciation, include in the emission test any fluorinated greenhouse gas that occurs in more than trace concentrations in the vent stream or, where a destruction device is used, in the inlet to the destruction device. You may include startup and shutdown events if the testing is sufficiently long or comprehensive to ensure that such events are not overrepresented in the emission factor. Malfunction events must not be included in the testing. If you do not detect a fluorinated GHG that was identified in the scoping speciation or that occurs in more than trace concentrations in the vent stream or in the inlet to the destruction device, assume that fluorinated GHG was emitted at one half of the detection limit. (2) Number of runs. For continuous processes, sample the process vent for a minimum of three runs of 1 hour each. If the relative standard deviation (RSD) of the emission factor calculated based on the first three runs is greater than or equal to 0.15 for the emission factor, continue to sample the process vent for an additional three runs of 1 hour each. If more than one fluorinated GHG is measured, the RSD must be expressed in terms of total CO 2 e. (3) Process activity measurements. Determine the mass rate of process feed, process production, or other process activity as applicable during the test using flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better. These devices may be the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of volume measurements and bulk density, etc.) if these devices or procedures meet the requirement. For monitoring ongoing process activity, use flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better. (4) Sample each process. If process vents from separate processes are manifolded together to a common vent or to a common destruction device, you must follow paragraph (c)(4)(i), (c)(4)(ii), or (c)(4)(iii) of this section. (i) You may sample emissions from each process in the ducts before the emissions are combined. (ii) You may sample in the common duct or at the outlet of the destruction device when only one process is operating. (iii) You may sample the combined emissions and use engineering calculations and assessments as specified in § 98.123(c)(4) to allocate the emissions to each manifolded process vent, provided the sum of the calculated fluorinated GHG emissions across the individual process vents is within 20 percent of the total fluorinated GHG emissions measured during the manifolded testing. (5) Emission test results. The results of an emission test must include the analysis of samples, number of test runs, the results of the RSD analysis, the analytical method used, determination of emissions, the process activity, and raw data and must identify the process, the operating scenario, the process vents tested, and the fluorinated GHGs that were included in the test. The emissions test report must contain all information and data used to derive the process-vent-specific emission factor, as well as key process conditions during the test. Key process conditions include those that are normally monitored for process control purposes and may include but are not limited to yields, pressures, temperatures, etc. ( e.g., of reactor vessels, distillation columns). (6) Emissions testing frequency. You must conduct emissions testing to develop the process-vent-specific emission factor under paragraph (c)(7)(i) or (c)(7)(ii) of this section, whichever occurs first: (i) 10-year revision. Conduct an emissions test every 10 years. In the calculations under § 98.123, apply the revised process-vent-specific emission factor to the process activity that occurs after the revision. (ii) Operating scenario change that affects the emission factor. For planned operating scenario changes, you must estimate and compare the emission calculation factors for the changed operating scenario and for the original operating scenario whose process vent specific emission factor was measured. Use the calculation methods in § 98.123(c)(4). If the emission calculation factor for the changed operating scenario is 15 percent or more different from the emission calculation factor for the previous operating scenario (this includes the cumulative change in the emission calculation factor since the last emissions test), you must conduct an emissions test to update the process-vent-specific emission factor, unless the difference between the operating scenarios is solely due to the application of a destruction device to emissions under the changed operating scenario. Conduct the test before February 28 of the year that immediately follows the change. In the calculations under § 98.123, apply the revised process-vent-specific emission factor to the process activity that occurs after the operating scenario change. (7) Subsequent measurements. If a continuous process vent with fluorinated GHG emissions less than 10,000 metric tons CO 2 e, per § 98.123(c)(2), is later found to have fluorinated GHG emissions of 10,000 metric tons CO 2 e or greater, you must conduct the emissions testing for the process vent during the following year and develop the process-vent-specific emission factor from the emissions testing. (8) Previous measurements. If you have conducted an emissions test less than 10 years before December 31, 2010, and the emissions testing meets the requirements in paragraphs (c)(1) through (c)(8) of this section, you may use the previous emissions testing to develop process-vent-specific emission factors. For purposes of paragraph (c)(7)(i) of this section, the date of the previous emissions test rather than December 31, 2010 shall constitute the beginning of the 10-year re-measurement cycle. (d) Emission calculation factor monitoring. If you determine fluorinated GHG emissions using the site-specific process-vent-specific emission calculation factor, you must meet the requirements in paragraphs (d)(1) through (d)(4) of this section. (1) Operating scenario. Perform the emissions calculation for the process vent based on representative performance of the operating scenario of the process. If more than one operating scenario applies to the process that contains the subject process vent, you must conduct a separate emissions calculation for operation under each operating scenario. For each continuous process vent that contains more than trace concentrations of any fluorinated GHG and for each batch process vent that contains more than trace concentrations of any fluorinated GHG, develop the process-vent-specific emission calculation factor for each operating scenario. For continuous process vents, determine the emissions based on the process activity for the representative performance of the operating scenario. For batch process vents, determine emissions based on the process activity for each typical batch operating scenario. (2) Process activity measurements. Use flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better for monitoring ongoing process activity. (3) Emission calculation results. The emission calculation must be documented by identifying the process, the operating scenario, and the process vents. The documentation must contain the information and data used to calculate the process-vent-specific emission calculation factor. (4) Operating scenario change that affects the emission calculation factor. For planned operating scenario changes that are expected to change the process-vent-specific emission calculation factor, you must conduct an emissions calculation to update the process-vent-specific emission calculation factor. In the calculations under § 98.123, apply the revised emission calculation factor to the process activity that occurs after the operating scenario change. (5) Previous calculations. If you have performed an emissions calculation for the process vent and operating scenario less than 10 years before December 31, 2010, and the emissions calculation meets the requirements in paragraphs (d)(1) through (d)(4) of this section and in § 98.123(c)(4)(i) and (c)(4)(ii), you may use the previous calculation to develop the site-specific process-vent-specific emission calculation factor. (e) Emission and stream testing, including analytical methods. Select and document testing and analytical methods as follows: (1) Sampling and mass measurement for emission testing. For emission testing in process vents or at the stack, use methods for sampling, measuring volumetric flow rates, non-fluorinated-GHG gas analysis, and measuring stack gas moisture that have been validated using a scientifically sound validation protocol. (i) Sample and velocity traverses. Acceptable methods include but are not limited to EPA Method 1 or 1A in Appendix A-1 of 40 CFR part 60. (ii) Velocity and volumetric flow rates. Acceptable methods include but are not limited to EPA Method 2, 2A, 2B, 2C, 2D, 2F, or 2G in Appendix A-1 of 40 CFR part 60. Alternatives that may be used for determining flow rates include OTM-24 (incorporated by reference, see § 98.7) and ALT-012 (incorporated by reference, see § 98.7). (iii) Non-fluorinated-GHG gas analysis. Acceptable methods include but are not limited to EPA Method 3, 3A, or 3B in Appendix A-1 of 40 CFR part 60. (iv) Stack gas moisture. Acceptable methods include but are not limited to EPA Method 4 in Appendix A-1 of 40 CFR part 60. (2) Analytical methods. Use a quality-assured analytical measurement technology capable of detecting the analyte of interest at the concentration of interest and use a sampling and analytical procedure validated with the analyte of interest at the concentration of interest. Where calibration standards for the analyte are not available, a chemically similar surrogate may be used. Acceptable analytical measurement technologies include but are not limited to gas chromatography (GC) with an appropriate detector, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR). Acceptable methods for determining fluorinated GHGs include EPA Method 18 in appendix A-1 of 40 CFR part 60, EPA Method 320 in appendix A of 40 CFR part 63, EPA 430-R-10-003 (incorporated by reference, see § 98.7), ASTM D6348-03 (incorporated by reference, see § 98.7), or other analytical methods validated using EPA Method 301 at 40 CFR part 63, appendix A or some other scientifically sound validation protocol. Acceptable methods for determining total fluorine concentrations for fluorine-containing compounds in streams under paragraph (b)(3) of this section include ASTM D7359-08 (incorporated by reference, see § 98.7), or other analytical methods validated using EPA Method 301 at 40 CFR part 63, appendix A or some other scientifically sound validation protocol. The validation protocol may include analytical technology manufacturer specifications or recommendations. (3) Documentation in GHG Monitoring Plan. Describe the sampling, measurement, and analytical method(s) used under paragraphs (e)(1) and (e)(2) of this section in the GHG Monitoring Plan as required under § 98.3(g)(5). Identify the methods used to obtain the samples and measurements listed under paragraphs (e)(1)(i) through (e)(1)(iv) of this section. At a minimum, include in the description of the analytical method a description of the analytical measurement equipment and procedures, quantitative estimates of the method's accuracy and precision for the analytes of interest at the concentrations of interest, as well as a description of how these accuracies and precisions were estimated, including the validation protocol used. (f) Emission monitoring for pieces of equipment. If you conduct a site-specific leak detection method or monitoring approach for pieces of equipment, follow paragraph (f)(1) or (f)(2) of this section and follow paragraph (f)(3) of this section. (1) Site-specific leak monitoring approach. You may develop a site-specific leak monitoring approach. You must validate the leak monitoring method and describe the method and the validation in the GHG Monitoring Plan. To validate the site-specific method, you may, for example, release a known rate of the fluorinated GHGs or surrogates of interest, or you may compare the results of the site-specific method to those of a method that has been validated for the fluorinated GHGs or surrogates of interest. In the description of the leak detection method and its validation, include a detailed description of the method, including the procedures and equipment used and any sampling strategies. Also include the rationale behind the method, including why the method is expected to result in an unbiased estimate of emissions from equipment leaks. If the method is based on methods that are used to detect or quantify leaks or other emissions in other regulations, standards, or guidelines, identify and describe the regulations, standards, or guidelines and why their methods are applicable to emissions of fluorinated GHGs or surrogates from leaks. Account for possible sources of error in the method, e.g., instrument detection limits, measurement biases, and sampling biases. Describe validation efforts, including but not limited to any comparisons against standard leaks or concentrations, any comparisons against other methods, and their results. If you use the Screening Ranges Approach, the EPA Correlation Approach, or the Unit-Specific Correlation Approach with a monitoring instrument that does not meet all of the specifications in EPA Method 21 at 40 CFR part 60, appendix A-7, then explain how and why the monitoring instrument, as used at your facility, would nevertheless be expected to accurately detect and quantify emissions of fluorinated GHGs or surrogates from process equipment, and describe how you verified its accuracy. For all methods, provide a quantitative estimate of the accuracy and precision of the method. (2) EPA Method 21 monitoring. If you determine that EPA Method 21 at 40 CFR part 60, appendix A-7 is appropriate for monitoring a fluorinated GHG, conduct the screening value concentration measurements using EPA Method 21 at 40 CFR part 60, appendix A-7 to determine the screening range data or the actual screening value data for the Screening Ranges Approach, EPA Correlation Approach, or the Unit-Specific Correlation Approach. For the one-time testing to develop the Unit-Specific Correlation equations in EPA-453/R-95-017 (incorporated by reference, see § 98.7), conduct the screening value concentration measurements using EPA Method 21 at 40 CFR part 60, appendix A-7 and the bagging procedures to measure mass emissions. Concentration measurements of bagged samples must be conducted using gas chromatography following EPA Method 18 analytical procedures or other method according to § 98.124(e). Use methane or other appropriate compound as the calibration gas. (3) Frequency of measurement and sampling. If you estimate emissions based on monitoring of equipment, conduct monitoring at least annually. Sample at least one-third of equipment annually (except for equipment that is unsafe-to-monitor, difficult-to-monitor, insulated, or in heavy liquid service, pumps with dual mechanical seals, agitators with dual mechanical seals, pumps with no external shaft, agitators with no external shaft, pressure relief devices in gas and vapor service with an upstream rupture disk, sampling connection systems with closed-loop or closed purge systems, and pieces of equipment whose leaks are routed through a closed vent system to a destruction device), changing the sample each year such that at the end of three years, all equipment in the process has been monitored. If you estimate emissions based on a sample of the equipment in the process, ensure that the sample is representative of the equipment in the process. If you have multiple processes that have similar types of equipment in similar service, and that produce or transform similar fluorinated GHGs (in terms of chemical composition, molecular weight, and vapor pressure) at similar pressures and concentrations, then you may annually sample all of the equipment in one third of these processes rather than one third of the equipment in each process. (g) Destruction device performance testing. If you vent or otherwise feed fluorinated GHGs into a destruction device and apply the destruction efficiency of the device to one or more fluorinated GHGs in § 98.123, you must conduct emissions testing to determine the destruction efficiency for each fluorinated GHG to which you apply the destruction efficiency. You must either determine the destruction efficiency for the most-difficult-to-destroy fluorinated GHG fed into the device (or a surrogate that is still more difficult to destroy) and apply that destruction efficiency to all the fluorinated GHGs fed into the device or alternatively determine different destruction efficiencies for different groups of fluorinated GHGs using the most-difficult-to-destroy fluorinated GHG of each group (or a surrogate that is still more difficult to destroy). (1) Destruction efficiency testing. You must sample the inlet and outlet of the destruction device for a minimum of three runs of 1 hour each to determine the destruction efficiency. You must conduct the emissions testing using the methods in paragraph (e) of this section. To determine the destruction efficiency, emission testing must be conducted when operating at high loads reasonably expected to occur (i.e., representative of high total fluorinated GHG load that will be sent to the device) and when destroying the most-difficult-to-destroy fluorinated GHG (or a surrogate that is still more difficult to destroy) that is fed into the device from the processes subject to this subpart or that belongs to the group of fluorinated GHGs for which you wish to establish a DE. If the outlet concentration of a fluorinated GHG that is fed into the device is below the detection limit of the method, you may use a concentration of one-half the detection limit to estimate the destruction efficiency. (i) If perfluoromethane (CF 4 ) is vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved specifically for CF 4 to take credit for the CF 4 emissions reduction. (ii) If sulfur hexafluoride (SF 6 ) is vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved specifically for SF 6 , or alternatively for CF 4 as a surrogate, to take credit for the SF 6 emissions reduction. (iii) If saturated perfluorocarbons other than CF 4 are vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved for the lowest molecular weight saturated perfluorocarbon vented to the destruction device, or alternatively for a lower molecular weight saturated PFC or SF 6 as a surrogate, to take credit for the PFC emission reduction. (iv) For all other fluorinated GHGs that are vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved for the most-difficult-to-destroy fluorinated GHG or surrogate vented to the destruction device. Examples of acceptable surrogates include the Class 1 compounds (ranked 1 through 34) in Appendix D, Table D-1 of “Guidance on Setting Permit Conditions and Reporting Trial Burn Results; Volume II of the Hazardous Waste Incineration Guidance Series,” January 1989, EPA Publication EPA 625/6-89/019. You can obtain a copy of this publication by contacting the Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov. (2) Destruction efficiency testing frequency. You must conduct emissions testing to determine the destruction efficiency as provided in paragraphs (g)(2)(i) or (ii) of this section, whichever occurs first: (i) Conduct an emissions test every 10 years. In the calculations under § 98.123, apply the updated destruction efficiency to the destruction that occurs after the test. (ii) Destruction device changes that affect the destruction efficiency. If you make a change to the destruction device that would be expected to affect the destruction efficiency, you must conduct an emissions test to update the destruction efficiency. Conduct the test before the February 28 of the year that immediately follows the change. In the calculations under § 98.123, apply the updated destruction efficiency to the destruction that occurs after the change to the device. (3) Previous testing .If you have conducted an emissions test within the 10 years prior to December 31, 2010, and the emissions testing meets the requirements in paragraph (g)(1) of this section, you may use the destruction efficiency determined during this previous emissions testing. For purposes of paragraph (g)(2)(i) of this section, the date of the previous emissions test rather than December 31, 2010 shall constitute the beginning of the 10-year re-measurement cycle. (4) Hazardous Waste Combustor testing. If a destruction device used to destroy fluorinated GHG is subject to subpart EEE of part 63 of this chapter or any portion of parts 260-270 of this chapter, you may apply the destruction efficiency specifically determined for CF 4 , SF 6 , PFCs other than CF 4 , and all other fluorinated GHGs under that test if the testing meets the criteria in paragraph (g)(1)(i) through (g)(1)(iv) of this section. If the testing of the destruction efficiency under subpart EEE of part 63 of this chapter was conducted more than 10 years ago, you may use the most recent destruction efficiency test provided that the design, operation, or maintenance of the destruction device has not changed since the last destruction efficiency test in a manner that could affect the ability to achieve the destruction efficiency, and the hazardous waste is fed into the normal flame zone. (h) Mass of previously produced fluorinated GHGs fed into destruction device. You must measure the mass of each fluorinated GHG that is fed into the destruction device in more than trace concentrations and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of ±1 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, you must measure the concentration of the fluorinated GHG being destroyed. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG fed into the destruction device. (i) Emissions due to malfunctions of destruction device. In their estimates of the mass of fluorinated GHG destroyed, fluorinated gas production facilities that destroy fluorinated GHGs must account for any temporary reductions in the destruction efficiency that result from any malfunctions of the destruction device, including periods of operation outside of the operating conditions defined in operating permit requirements and/or destruction device manufacturer specifications. (j) Emissions due to process startup, shutdown, or malfunctions. Fluorinated GHG production facilities must account for fluorinated GHG emissions that occur as a result of startups, shutdowns, and malfunctions, either recording fluorinated GHG emissions during these events, or documenting that these events do not result in significant fluorinated GHG emissions. Facilities may use the calculation methods in § 98.123(c)(1) to estimate emissions during startups, shutdowns, and malfunctions. (k) Monitoring for venting residual fluorinated GHG in containers. Measure the residual fluorinated GHG in containers received by the facility either using scales or using pressure and temperature measurements. You may use pressure and temperature measurements only in cases where no liquid fluorinated GHG is present in the container. Scales must have an accuracy and precision of ±1 percent or better of the filled weight (gas plus tare) of the containers of fluorinated GHGs that are typically weighed on the scale. For example, for scales that are generally used to weigh cylinders that contain 115 pounds of gas when full and that have a tare weight of 115 pounds, this equates to ±1 percent of 230 pounds, or ±2.3 pounds. Pressure gauges and thermometers used to measure quantities that are monitored under this paragraph must have an accuracy and precision of ±1 percent of full scale or better. (l) Initial scoping speciations, emissions testing, emission factor development, emission calculation factor development, emission characterization development, and destruction efficiency determinations must be completed by February 29, 2012 for processes and operating scenarios that operate between December 31, 2010 and December 31, 2011. For other processes and operating scenarios, initial scoping speciations, emissions testing, emission factor development, emission calculation factor development, emission characterization development, and destruction efficiency determinations must be complete by February 28 of the year following the year in which the process or operating scenario commences or recommences. (m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using monitoring instruments traceable to the International System of Units (SI) through the National Institute of Standards and Technology (NIST) or other recognized national measurement institute. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use any of the following applicable flow meter test methods or the calibration procedures specified by the flow meter, weigh-scale, or other volumetric or density measure manufacturer. (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7). (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7). (3) ASME-MFC-5M-1985, (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7). (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7). (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7). (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see § 98.7). (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7). (n) All analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs and associated detectors, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR) devices, must be calibrated at a frequency needed to support the type of analysis specified in the GHG Monitoring Plan as required under § 98.124(e)(3) and 93.3(g)(5). Quality assurance samples at the concentrations of concern must be used for the calibration. Such quality assurance samples must consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration must be performed by a method specified in the GHG Monitoring Plan. (o) Special provisions for estimating 2011 and subsequent year emissions. (1) Best available monitoring methods. To estimate emissions that occur from January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for any parameter that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart. The owner or operator must use the calculation methodologies and equations in § 98.123, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, or operate a required piece of monitoring equipment, to procure measurement services from necessary providers, or to gain physical access to make required measurements in a facility by January 1, 2011. Starting no later than July 1, 2011, 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 paragraphs (o)(2) through (o)(4) of this section. Best available monitoring methods means any of the following methods specified in this paragraph: (i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart. (ii) Supplier data. (iii) Engineering calculations or assessments. (iv) Other company records. (2) Requests for extension of the use of best available monitoring methods to estimate 2011 emissions: parameters other than scoping speciations, emission factors, and emission characterizations. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods for parameters other than scoping speciations, emission factors, or emission characterizations to estimate emissions that occur between July 1, 2011 and December 31, 2011. (i) Timing of request. The extension request must be submitted to EPA no later than February 28, 2011. (ii) Content of request. Requests must contain the following information: (A) A list of specific items of monitoring equipment and measurement services for which the request is being made and the locations (e.g., processes and vents) where each piece of monitoring equipment will be installed and where each measurement service will be provided. (B) Identification of the specific rule requirements for which the monitoring equipment or measurement service is needed. (C) A description of the reasons why the needed equipment could not be obtained, installed, or operated or why the needed measurement service could not be provided before July 1, 2011. The owner or operator must consider all of the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical, logistical, or legal barrier exists. (D) If the reason for the extension is that the equipment cannot be purchased, delivered, or installed before July 1, 2011, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers, the dates by which alternative vendors promised delivery or installation, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery or installation, and the current expected date of delivery or installation. (E) If the reason for the extension is that service providers were unable to provide necessary measurement services, include supporting documentation demonstrating that these services could not be acquired before July 1, 2011. This documentation must include written correspondence to and from at least two service providers stating that they will not be able to provide the necessary services before July 1, 2011. (F) If the reason for the extension is that the process is operating continuously without process shutdown, include supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there is no opportunity before July 1, 2011 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown. (G) If the reason for the extension is that access to process streams, emissions streams, or destroyed streams, as applicable, could not be gained before July 1, 2011 for reasons other than the continuous operation of the process without shutdown, include illustrative documentation such as photographs and engineering diagrams demonstrating that access could not be gained. (H) A description of the best available monitoring methods that will be used and how their results will be applied (i.e., which calculation method will be used) to develop the emission estimate. Where the proposed best available monitoring method is the use of current monitoring data in the mass-balance approach, include the estimated relative and absolute errors of the mass-balance approach using the current monitoring data. (I) A description of the specific actions the owner or operator will take to comply with monitoring requirements by January 1, 2012. (3) Requests for extension of the use of best available monitoring methods to estimate 2011 emissions: scoping speciations, emission factors, and emission characterizations. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods for scoping speciations, emission factors, and emission characterizations to estimate emissions that occur between July 1, 2011 and December 31, 2011. (i) Timing of request. The extension request must be submitted to EPA no later than June 30, 2011. (ii) Content of request. Requests must contain the information outlined in paragraph (o)(2)(ii) of this section, substituting March 1, 2012 for July 1, 2011 and substituting March 1, 2013 for January 1, 2012. (iii) Reporting of 2011 emissions using scoping speciations, emission factors, and emission characterizations developed after February 29, 2012. Facilities that are approved to use best available monitoring methods in 2011 for scoping speciations, emission factors, or emission characterizations for certain processes must submit, by March 31, 2013, revised 2011 emission estimates that reflect the scoping speciations, emission factors, and emission characterizations that are measured for those processes after February 29, 2012. If the operating scenario for 2011 is different from all of the operating scenarios for which emission factors are developed after February 29, 2012, use Equation L-23 at § 98.123(c)(3)(viii) to adjust the emission factor(s) or emission characterizations measured for the post-February 29, 2012 operating scenario(s) to account for the differences. (4) Requests for extension of the use of best available monitoring methods to estimate emissions that occur after 2011. EPA does not anticipate approving the use of best available monitoring methods to estimate emissions that occur beyond December 31, 2011; however, EPA reserves the right to review requests for unique and extreme circumstances which include safety, technical infeasibility, or inconsistency with other local, State or Federal regulations. (i) Timing of request. The extension request must be submitted to EPA no later than June 30, 2011. (ii) Content of request. Requests must contain the following information: (A) The information outlined in paragraph (o)(2)(ii) of this section. For scoping speciations, emission factors, and emission characterizations, substitute March 1, 2013 for July 1, 2011 and substitute March 1, 2014 for January 1, 2012. For other parameters, substitute January 1, 2012 for July 1, 2011 and substitute January 1, 2013 for January 1, 2012. (B) A detailed outline of the unique circumstances necessitating an extension, including specific data collection issues that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with data collection. The owner or operator must consider all the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists. (C) A detailed explanation and supporting documentation of how and when the owner or operator will receive the required data and/or services to comply with the reporting requirements of this subpart in the future. (E) The Administrator reserves the right to require that the owner or operator provide additional documentation. (iii) Reporting of 2011 and subsequent year emissions using scoping speciations, emission factors, and emission characterizations developed after approval to use best available monitoring methods expires. Facilities that are approved to use best available monitoring methods in 2011 and subsequent years for scoping speciations, emission factors, or emission characterizations for certain processes must submit, by March 31 of the year that begins one year after their approval to use best available monitoring method(s) expires, revised emission estimates for 2011 and subsequent years that reflect the scoping speciations, emission factors, and emission characterizations that are measured for those processes in 2013 or subsequent years. If the operating scenario for 2011 or subsequent years is different from all of the operating scenarios for which emission factors or emission characterizations are developed in 2013 or subsequent years, use Equation L-23 of § 98.123(c)(3)(viii) to adjust the emission factor(s) or emission characterization(s) measured for the new operating scenario(s) to account for the differences. (5) 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, or operate the required piece of monitoring equipment, to procure measurement services from necessary providers, or to gain physical access to make required measurements in a facility according to the requirements of this subpart by the dates specified in paragraphs (o)(2), (3), and (4) of this section for any of the reasons described in paragraph (o)(2)(ii) of this section, or, for requests under paragraph (o)(4) of this section, any of the reasons described in paragraph (o)(4)(ii)(B) of this section." 40:40:23.0.1.1.2.12.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.125 Procedures for estimating missing data.,EPA,,,,"(a) A complete record of all measured parameters used in the GHG emissions calculations in § 98.123 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 (b) and (c) of this section. You must document and keep records of the procedures used for all such estimates. (b) For each missing value of the fluorinated GHG concentration or fluorine-containing compound concentration, the substitute data value must be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. (c) For each missing value of the mass produced, fed into the production process, fed into the transformation process, or fed into destruction devices, the substitute value of that parameter must be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter must be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device." 40:40:23.0.1.1.2.12.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.126 Data reporting requirements.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51489, Aug. 24, 2012; 78 FR 71954, Nov. 29, 2013; 79 FR 73787, Dec. 11, 2014]","(a) All facilities. In addition to the information required by § 98.3(c), you must report the information in paragraphs (a)(2) through (6) of this section according to the schedule in paragraph (a)(1) of this section, except as otherwise provided in paragraph (j) of this section or in § 98.3(c)(4)(vii) and Table A-7 of subpart A of this part. (1) Frequency of reporting under paragraph (a) of this section. The information in paragraphs (a)(2) through (6) of this section must be reported annually. (2) Generically-identified process. For each production and transformation process at the facility, you must: (i) Provide a number, letter, or other identifier for the process. This identifier must be consistent from year to year. (ii) Indicate whether the process is a fluorinated gas production process, a fluorinated gas transformation process where no fluorinated GHG reactant is produced at another facility, or a fluorinated gas transformation process where one or more fluorinated GHG reactants are produced at another facility. (iii) Indicate whether the process could be characterized as reaction, distillation, or packaging (include all that apply). (iv) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from vents ( i.e., mass balance (for reporting years 2011, 2012, 2013, and 2014 only), process-vent-specific emission factor, or process-vent-specific emission calculation factor). (v) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from equipment leaks, unless you used the mass balance method (for reporting years 2011, 2012, 2013, and 2014 only) for that process. (3) Emissions from production and transformation processes, process level, multiple products. If your facility produces more than one fluorinated gas product, for each generically-identified process and each fluorinated GHG group, you must report the total GWP-weighted emissions of all fluorinated GHGs in that group from the process, in metric tons CO 2 e. (4) Emissions from production and transformation processes, facility level, multiple products. If your facility produces more than one fluorinated gas product, you must report the information in paragraphs (a)(4)(i) and (ii) of this section, as applicable, for emissions from production and transformation processes. (i) For each fluorinated GHG with emissions of 1,000 metric tons of CO 2 e or more from production and transformation processes, summed across the facility as a whole, you must report the total mass in metric tons of the fluorinated GHG emitted from production and transformation processes, summed across the facility as a whole. If the fluorinated GHG does not have a chemical-specific GWP in Table A-1 of subpart A, identify the fluorinated GHG group of which that fluorinated GHG is a member. (ii) For all other fluorinated GHGs emitted from production and transformation processes, you must report the total GWP-weighted emissions from production and transformation processes of those fluorinated GHGs by fluorinated GHG group, summed across the facility as a whole, in metric tons of CO 2 e. (5) Emissions from production and transformation processes, facility level, one product only. If your facility produces only one fluorinated gas product, aggregate and report the total GWP-weighted emissions from production and transformation processes of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons of CO 2 e, with the following exception: Where emissions consist of a major fluorinated GHG constituent of a fluorinated gas product, and the product is sold or transferred to another person, report the total mass in metric tons of each fluorinated GHG that is emitted from production and transformation processes and that is a major fluorinated GHG constituent of the product. If the fluorinated GHG does not have a chemical-specific GWP in Table A-1 of subpart A, identify the fluorinated GHG group of which that fluorinated GHG is a member. (6) Effective destruction efficiency. For each generically-identified process, use Table L-1 of this subpart to report the range that encompasses the effective destruction efficiency, DE effective , calculated for that process using Equation L-35 of this subpart. The effective destruction efficiency must be reported on a CO 2 e basis. (b) Reporting for mass balance method for reporting years 2011, 2012, 2013, and 2014. If you used the mass balance method to calculate emissions for any of the reporting years 2011, 2012, 2013, or 2014, you must conduct mass balance reporting for that reporting year. For processes whose emissions were determined using the mass balance method under the former § 98.123(b), as included in paragraph 1 of Appendix A of this subpart, you must report the information listed in paragraphs (b)(1) and (b)(2) of this section for each process on an annual basis. (1) If you calculated the relative and absolute errors under the former § 98.123(b)(1), the overall absolute and relative errors calculated for the process under the former § 98.123(b)(1), in metric tons CO 2 e and decimal fraction, respectively. (2) The method used to estimate the total mass of fluorine in destroyed or recaptured streams (specify the former § 98.123(b)(4) or (15), as included in paragraph 1 of Appendix A of this subpart). (c) Reporting for emission factor and emission calculation factor approach. For processes whose emissions are determined using the emission factor approach under § 98.123(c)(3) or the emission calculation factor under § 98.123(c)(4), you must report the following for each generically-identified process. (1) [Reserved] (2) [Reserved] (3) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from all process vents combined, in metric tons of CO 2 e. (4) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from equipment leaks, in metric tons of CO 2 e. (d) Reporting for missing data. Where missing data have been estimated pursuant to § 98.125, you must report: (1) The generically-identified process for which the data were missing. (2) The reason the data were missing, the length of time the data were missing, and the method used to estimate the missing data. (3) Estimates of the missing data for all missing data associated with data elements required to be reported in this section. (e) Reporting of destruction device excess emissions data. Each fluorinated gas production facility that destroys fluorinated GHGs must report the excess emissions that result from malfunctions of the destruction device, and these excess emissions must be reflected in the fluorinated GHG estimates in the former § 98.123(b) as included in paragraph 1 of Appendix A of this subpart for the former mass balance method, and in § 98.123(c). Such excess emissions would occur if the destruction efficiency was reduced due to the malfunction. (f) Reporting of destruction device testing. By March 31, 2012 or by March 31 of the year immediately following the year in which it begins fluorinated GHG destruction, each fluorinated gas production facility that destroys fluorinated GHGs must submit a report containing the information in paragraphs (f)(1) through (f)(4) of this section. This report is one-time unless you make a change to the destruction device that would be expected to affect its destruction efficiencies. (1) [Reserved] (2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate the destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1), vented to the destruction device. (3) Date of the most recent destruction device test. (4) Name of all applicable Federal or State regulations that may apply to the destruction process. (5) [Reserved] (g) Reporting for destruction of previously produced fluorinated GHGs. Each fluorinated gas production facility that destroys fluorinated GHGs must report, separately from the fluorinated GHG emissions reported under paragraphs (b) or (c) of this section, the following for each previously produced fluorinated GHG destroyed: (1) [Reserved] (2) The mass of the fluorinated GHG emitted from the destruction device (metric tons). (h) Reporting of emissions from venting of residual fluorinated GHGs from containers. Each fluorinated gas production facility that vents residual fluorinated GHGs from containers must report the following for each fluorinated GHG vented: (1) The mass of the residual fluorinated GHG vented from containers annually (metric tons). (2) [Reserved] (i) Reporting of fluorinated GHG products of incomplete combustion (PICs) of fluorinated gases. Each fluorinated gas production facility that destroys fluorinated gases must submit a one-time report by June 30, 2011, that describes any measurements, research, or analysis that it has performed or obtained that relate to the formation of products of incomplete combustion that are fluorinated GHGs during the destruction of fluorinated gases. The report must include the methods and results of any measurement or modeling studies, including the products of incomplete combustion for which the exhaust stream was analyzed, as well as copies of relevant scientific papers, if available, or citations of the papers, if they are not. No new testing is required to fulfill this requirement. (j) Special provisions for reporting years 2011, 2012, and 2013 only. For reporting years 2011, 2012, and 2013, the owner or operator of a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of this section. (1) Timing. The owner or operator of a facility is not required to report the data elements at § 98.3(c)(4)(iii) and paragraphs (a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section until the later of March 31, 2015 or the date set forth for that data element at § 98.3(c)(4)(vii) and Table A-7 of Subpart A of this part. (2) Excess emissions. Excess emissions of fluorinated GHGs resulting from destruction device malfunctions must be reflected in the reported facility-wide CO 2 e emissions but are not required to be reported separately. (3) Calculation and reporting of CO 2 e. You must report the total fluorinated GHG emissions covered by this subpart, expressed in metric tons of CO 2 e. This includes emissions from all fluorinated gas production processes, all fluorinated gas transformation processes that are not part of a fluorinated gas production process, all fluorinated gas destruction processes that are not part of a fluorinated gas production process or a fluorinated gas transformation process, and venting of residual fluorinated GHGs from containers returned from the field. To convert fluorinated GHG emissions to CO 2 e for reporting under this section, use Equation A-1 of § 98.2. For fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use either the default GWP specified below or your best estimate of the GWP based on the information described in § 98.123(c)(1)(vi)(A)( 3 ). Use of quantitative structure activity relationships (QSARs) is an acceptable method for determining GWPs in situations where pure standards of the “target” fluorinated GHG are not available, the “target” fluorinated GHG cannot be isolated from gas streams, and FTIR spectra for the impurities are not available. (i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs. (ii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO 2 e, that were calculated using the default GWP of 2000. (iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO 2 e, that were calculated using the default GWP of 10,000. (iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO 2 e, that were calculated using your best estimate of the GWP. (k) Submission of complete reporting year 2011, 2012, and 2013 GHG reports. By March 31, 2015, you must submit annual GHG reports for reporting years 2011, 2012, and 2013 that contain the information specified in paragraphs (a) through (i) of this section. The reports must calculate CO 2 e using the GWPs in Table A-1 of subpart A of this part (as in effect on January 1, 2015). Prior submission of partial reports for these reporting years under paragraph (j) of this section does not affect your obligation to submit complete reports under this paragraph." 40:40:23.0.1.1.2.12.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.127 Records that must be retained.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 FR 73788, Dec. 11, 2014]","In addition to the records required by § 98.3(g), you must retain the dated records specified in paragraphs (a) through (l) of this section, as applicable. (a) Process information records. (1) Identify all products and processes subject to this subpart. Include the unit identification as appropriate, the generic process identification reported for the process under § 98.126(a)(2)(i) through (iii), and the product with which the process is associated. (2) Monthly and annual records, as applicable, of all analyses and calculations conducted as required under § 98.123, including the data monitored under § 98.124, and all information reported as required under § 98.126. (3) Identify all fluorinated GHGs with emissions of 1,000 metric tons CO 2 e or more from production and transformation processes, summed across the facility as a whole, and identify all fluorinated GHGs with total emissions less than 1,000 metric tons CO 2 e from production and transformation processes, summed across the facility as a whole. (4) Calculations used to determine the total GWP-weighted emissions of fluorinated GHGs by fluorinated GHG group for each process, in metric tons CO 2 e. (b) Scoping speciation. Retain records documenting the information collected under § 98.124(a). (c) Mass balance method. Retain the following records for each process for which the mass balance method was used to estimate emissions in reporting years 2011, 2012, 2013, or 2014. If you used an element other than fluorine in the mass balance equation pursuant to the former § 98.123(b)(3) as included in paragraph 1 of Appendix A of this subpart for the former mass balance method, substitute that element for fluorine in the recordkeeping requirements of this paragraph. (1) The data and calculations used to estimate the absolute and relative errors associated with use of the mass-balance approach. (2) The data and calculations used to estimate the mass of fluorine emitted from the process. (3) The data and calculations used to determine the fractions of the mass emitted consisting of each reactant (FER d ), product (FEP), and by-product (FEB k ), including the preliminary calculations in the former § 98.123(b)(8)(i). (d) Emission factor and emission calculation factor method. Retain the following records for each process for which the emission factor or emission calculation factor method was used to estimate emissions. (1) Identify all continuous process vents with emissions of fluorinated GHGs that are less than 10,000 metric tons CO 2 e per year and all continuous process vents with emissions of 10,000 metric tons CO 2 e per year or more. Include the data and calculation used to develop the preliminary estimate of emissions for each process vent. (2) Identify all batch process vents. (3) For each vent, identify the method used to develop the factor (i.e., emission factor by emissions test or emission calculation factor). (4) The emissions test data and reports (see § 98.124(c)(5)) and the calculations used to determine the process-vent-specific emission factor, including the actual process-vent-specific emission factor, the average hourly emission rate of each fluorinated GHG from the process vent during the test and the process feed rate, process production rate, or other process activity rate during the test. (5) The process-vent-specific emission calculation factor and the calculations used to determine the process-vent-specific emission calculation factor. (6) The annual process production quantity or other process activity information in the appropriate units, along with the dates and time period during which the process was operating and dates and time periods the process vents are vented to the destruction device. As an alternative to date and time periods when process vents are vented to the destruction device, a facility may track dates and time periods that process vents by-pass the destruction device. (7) Calculations used to determine annual emissions of each fluorinated GHG for each process and the total fluorinated GHG emissions for all processes, i.e., total for facility. (e) Destruction efficiency testing. A fluorinated GHG production facility that destroys fluorinated GHGs and reflects this destruction in § 98.123 must retain the emissions performance testing reports (including revised reports) for each destruction device. The emissions performance testing report must contain all information and data used to derive the destruction efficiency for each fluorinated GHG whose destruction the facility reflects in § 98.123, as well as the key process and device conditions during the test. This information includes the following: (1) Destruction efficiency (DE) determined for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv). (2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1)(i) through (iv), vented to the destruction device. (3) Mass flow rate of the stream containing the fluorinated GHG(s) or surrogate into the device during the test. (4) Concentration (mass fraction) of each fluorinated GHG or surrogate in the stream flowing into the device during the test. (5) Concentration (mass fraction) of each fluorinated GHG or surrogate at the outlet of the destruction device during the test. (6) Mass flow rate at the outlet of the destruction device during the test. (7) Test methods and analytical methods used to determine the mass flow rates and fluorinated GHG (or surrogate) concentrations of the streams flowing into and out of the destruction device during the test. (8) Destruction device conditions that are normally monitored for device control, such as temperature, total mass flow rates into the device, and CO or O 2 levels. (9) Name of all applicable Federal or State regulations that may apply to the destruction process. (f) Equipment leak records. If you are subject to § 98.123(d) of this subpart, you must maintain information on the number of each type of equipment; the service of each piece of equipment (gas, light liquid, heavy liquid); the concentration of each fluorinated GHG in the stream; each piece of equipment excluded from monitoring requirement; the time period each piece of equipment was in service, and the emission calculations for each fluorinated GHG for all processes. Depending on which equipment leak monitoring approach you follow, you must maintain information for equipment on the associated screening data concentrations for greater than or equal to 10,000 ppmv and associated screening data concentrations for less than 10,000 ppmv; associated actual screening data concentrations; and associated screening data and leak rate data (i.e., bagging) used to develop a unit-specific correlation. If you developed and follow a site-specific leak detection approach, provide the records for monitoring events and the emissions estimation calculations, as appropriate, consistent with the approach for equipment leak emission estimation in your GHG Monitoring Plan. (g) Container heel records. If you vent residual fluorinated GHGs from containers, maintain the following records of the measurements and calculations used to estimate emissions of residual fluorinated GHGs from containers. (i) If you measure the contents of each container, maintain records of these measurements and the calculations used to estimate emissions of each fluorinated GHG from each container size and type. (ii) If you develop and apply container heel factors to estimate emissions, maintain records of the measurements and calculations used to develop the heel factor for each fluorinated GHG and each container size and type and of the number of containers of each fluorinated GHG and of each container size and type returned to your facility. (h) Missing data records. Where missing data have been estimated pursuant to § 98.125, you must record the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data. (i) All facilities. Dated records documenting the initial and periodic calibration of all analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs, gas chromatography-mass spectrometry (GC/MS), gas chromatograph-electron capture detector (GC/ECD), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR) devices, and all mass measurement equipment such as weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.124(e), (f), (g), (m), and (n). (j) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. (k) For fluorinated GHGs whose GWPs are not listed in Table A-1 to subpart A of this part, maintain records of the GWPs used to calculate facility-wide CO 2 e emissions under § 98.127(j). Where you used your best estimate of the GWP, maintain records of the data and analysis used to develop that GWP, including the data elements at § 98.123(c)(1)(vi)(A)( 1 )through ( 3 ). If you have used QSARs to estimate the GWP, include information documenting the level of accuracy of the QSAR-derived GWP, including information on how the structure of the “target” fluorinated GHG is similar to the structures of the fluorinated GHGs used to model the radiative forcing and/or reaction rate of the “target” fluorinated GHG, the quality and quantity of the measurements of the radiative forcings and/or reaction rates of the fluorinated GHGs used to model these parameters for the “target” fluorinated GHG, any estimated uncertainties of the modeled forcings and/or reaction rates, and descriptions and results of any efforts to validate the QSAR model(s). (l) Verification software records. For reporting year 2015 and thereafter, you must enter into verification software specified in § 98.5(b) the data specified in paragraphs (l)(1) through (15) of this section. The data specified in paragraphs (l)(1) through (11) must be entered for each process and each process vent, as applicable. The data specified in paragraphs (l)(1) through (15) must be entered for each fluorinated GHG, as applicable. 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 (l)(1) through (15) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (l)(1) through (15) of this section. (1) The identity of the process vent ( e.g., name or number assigned by the facility). (2) The equation used to estimate emissions from the process vent (Equations L-21, L-22, L-26, or L-27). (3) The type of process activity used to estimate emissions from the process vent ( e.g., product of process or reactant consumed by process) (Activity, Activity C, or Activity U ) (Equations L-21, L-22, L-26, L-27, L-35). (4) The quantities of the process activity used to estimate controlled and uncontrolled emissions, respectively, for the process vent, Activity, Activity U, or Activity C , ( e.g. kg product) (Equations L-21, L-22, L-26, L-27, L-35). (5) The site-specific, process-vent-specific emission factor, EF PV-C, for the process vent, measured after the destruction device (kg fluorinated GHG emitted per kg activity) (Equation L-21). (6) The site-specific, process-vent-specific emission calculation factor, ECF PV-U, for the process vent, for periods not vented to destruction device (kg fluorinated GHG emitted per kg activity) (Equations L-21, L-35). (7) The site-specific, process-vent-specific emission factor(s), EF PV-U, for the process vent, measured before the destruction device (kg fluorinated GHG emitted per kg activity) (Equations L-22, L-35). (8) The site-specific, process-vent-specific emission calculation factor for the process vent, ECF PV (kg fluorinated GHG emitted per kg of activity) (Equations L-26, L-27, L-35). (9) Destruction efficiency, DE, of each destruction device for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv) (weight fraction) (Equations L-22, L-27, L-31). (10) Emissions of each fluorinated GHG for equipment pieces for the process, E ELf (metric ton/yr) (98.123(d)(3)). (11) The mass of the fluorinated GHG previously produced and fed into the destruction device, RE D , (metric tons) (Equation L-31). (12) If applicable, the heel factor, h fj , calculated for each container size and type (decimal fraction) (Equation L-34). (13) If applicable, the number of containers of size and type j returned to the fluorinated gas production facility, N fj , (Equation L-34). (14) If applicable, the full capacity of containers of size and type j containing fluorinated GHG f, F fj , (metric tons) (Equation L-34). (15) For fluorinated GHGs that do not have a chemical-specific GWP on Table A-1 of subpart A of this part, the fluorinated GHG group of which the fluorinated GHG is a member, as applicable (to permit look-up of global warming potential, GWP f , or GWP i , for that fluorinated GHG in Table A-1 of subpart A of this part (Equation A-1 of subpart A of this part, Equation L-35))." 40:40:23.0.1.1.2.12.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,L,Subpart L—Fluorinated Gas Production,,§ 98.128 Definitions.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 FR 73789, Dec. 11, 2014]","Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart. Batch process or batch operation means a noncontinuous operation involving intermittent or discontinuous feed into equipment, and, in general, involves the emptying of the equipment after the batch operation ceases and prior to beginning a new operation. Addition of raw material and withdrawal of product do not occur simultaneously in a batch operation. Batch emission episode means a discrete venting episode associated with a vessel in a process; a vessel may have more than one batch emission episode. For example, a displacement of vapor resulting from the charging of a vessel with a feed material will result in a discrete emission episode that will last through the duration of the charge and will have an average flow rate equal to the rate of the charge. If the vessel is then heated, there will also be another discrete emission episode resulting from the expulsion of expanded vapor. Other emission episodes also may occur from the same vessel and other vessels in the process, depending on process operations. By-product means a chemical that is produced coincidentally during the production of another chemical. Completely destroyed means destroyed with a destruction efficiency of 99.99 percent or greater. Completely recaptured means 99.99 percent or greater of each fluorinated GHG is removed from a stream. Continuous process or operation means a process where the inputs and outputs flow continuously throughout the duration of the process. Continuous processes are typically steady state. Destruction device means any device used to destroy fluorinated GHG. Destruction process means a process used to destroy fluorinated GHG in a destruction device such as a thermal incinerator or catalytic oxidizer. Difficult-to-monitor means the equipment piece may not be monitored without elevating the monitoring personnel more than 2 meters (7 feet) above a support surface or it is not accessible in a safe manner when it is in fluorinated GHG service. Dual mechanical seal pump and dual mechanical seal agitator means a pump or agitator equipped with a dual mechanical seal system that includes a barrier fluid system where the barrier fluid is not in light liquid service; each barrier fluid system is equipped with a sensor that will detect failure of the seal system, the barrier fluid system, or both; and meets the following requirements: (1) Each dual mechanical seal system is operated with the barrier fluid at a pressure that is at all times (except periods of startup, shutdown, or malfunction) greater than the pump or agitator stuffing box pressure; or (2) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or connected by a closed-vent system to a control device; or (3) Equipped with a closed-loop system that purges the barrier fluid into a process stream. Equipment (for the purposes of § 98.123(d) and § 98.124(f) only) means each pump, compressor, agitator, pressure relief device, sampling connection system, open-ended valve or line, valve, connector, and instrumentation system in fluorinated GHG service for a process subject to this subpart; and any destruction devices or closed-vent systems to which processes subject to this subpart are vented. Fluorinated gas means any fluorinated GHG, CFC, or HCFC. Fluorinated gas product means the product of the process, including isolated intermediates. Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in which all available valence locations are filled by fluorine atoms. This includes but is not limited to saturated perfluorocarbons, SF 6 , NF 3 , SF 5 CF 3 , fully fluorinated linear, branched and cyclic alkanes, fully fluorinated ethers, fully fluorinated tertiary amines, fully fluorinated aminoethers, and perfluoropolyethers. Generically-identified process means a process that is: (1) Identified as a production process, a transformation process where no fluorinated GHG reactant is produced at another facility, or a transformation process where one or more fluorinated GHG reactants are produced at another facility; (2) Further identified as a reaction, distillation, or packaging process, or a combination thereof; and (3) Tagged with a discrete identifier, such as a letter or number, that remains constant from year to year. In fluorinated GHG service means that a piece of equipment either contains or contacts a feedstock, by-product, or product that is a liquid or gas and contains at least 5 percent by weight fluorinated GHG. In gas and vapor service means that a piece of equipment in regulated material service contains a gas or vapor at operating conditions. In heavy liquid service means that a piece of equipment in regulated material service is not in gas and vapor service or in light liquid service. In light liquid service means that a piece of equipment in regulated material service contains a liquid that meets the following conditions: (1) The vapor pressure of one or more of the compounds is greater than 0.3 kilopascals at 20 °C. (2) The total concentration of the pure compounds constituents having a vapor pressure greater than 0.3 kilopascals at 20 °C is equal to or greater than 20 percent by weight of the total process stream. (3) The fluid is a liquid at operating conditions. Vapor pressures may be determined by standard reference texts or ASTM D-2879, (incorporated by reference, see § 98.7). In vacuum service means that equipment is operating at an internal pressure which is at least 5 kilopascals below ambient pressure. Isolated intermediate means a product of a process that is stored before subsequent processing. An isolated intermediate is usually a product of chemical synthesis. Storage of an isolated intermediate marks the end of a process. Storage occurs at any time the intermediate is placed in equipment used solely for storage. Major fluorinated GHG constituent means a fluorinated GHG constituent of a fluorinated gas product that occurs in concentrations greater than 1 percent by mass. No external shaft pump and No external shaft agitator means any pump or agitator that is designed with no externally actuated shaft penetrating the pump or agitator housing. Operating scenario means any specific operation of a process and includes the information specified in paragraphs (1) through (5) of this definition for each process. A change or series of changes to any of these elements, except for paragraph (4) of this definition, constitutes a different operating scenario. (1) A description of the process, the specific process equipment used, and the range of operating conditions for the process. (2) An identification of related process vents, their associated emissions episodes and durations, and calculations and engineering analyses to show the annual uncontrolled fluorinated GHG emissions from the process vent. (3) The control or destruction devices used, as applicable, including a description of operating and/or testing conditions for any associated destruction device. (4) The process vents (including those from other processes) that are simultaneously routed to the control or destruction device(s). (5) The applicable monitoring requirements and any parametric level that assures destruction or removal for all emissions routed to the control or destruction device. Process means all equipment that collectively functions to produce a fluorinated gas product, including an isolated intermediate (which is also a fluorinated gas product), or to transform a fluorinated gas product. A process may consist of one or more unit operations. For the purposes of this subpart, process includes any, all, or a combination of reaction, recovery, separation, purification, or other activity, operation, manufacture, or treatment which are used to produce a fluorinated gas product. For a continuous process, cleaning operations conducted may be considered part of the process, at the discretion of the facility. For a batch process, cleaning operations are part of the process. Ancillary activities are not considered a process or part of any process under this subpart. Ancillary activities include boilers and incinerators, chillers and refrigeration systems, and other equipment and activities that are not directly involved (i.e., they operate within a closed system and materials are not combined with process fluids) in the processing of raw materials or the manufacturing of a fluorinated gas product. Process condenser means a condenser whose primary purpose is to recover material as an integral part of a process. All condensers recovering condensate from a process vent at or above the boiling point or all condensers in line prior to a vacuum source are considered process condensers. Typically, a primary condenser or condensers in series are considered to be integral to the process if they are capable of and normally used for the purpose of recovering chemicals for fuel value (i.e., net positive heating value), use, reuse or for sale for fuel value, use, or reuse. Process vent (for the purposes of this subpart only) means a vent from a process vessel or vents from multiple process vessels within a process that are manifolded together into a common header, through which a fluorinated GHG-containing gas stream is, or has the potential to be, released to the atmosphere (or the point of entry into a control device, if any). Examples of process vents include, but are not limited to, vents on condensers used for product recovery, bottoms receivers, surge control vessels, reactors, filters, centrifuges, and process tanks. Process vents do not include vents on storage tanks, wastewater emission sources, or pieces of equipment. Typical batch means a batch process operated within a range of operating conditions that are documented in an operating scenario. Emissions from a typical batch are based on the operating conditions that result in representative emissions. The typical batch defines the uncontrolled emissions for each emission episode defined under the operating scenario. Uncontrolled fluorinated GHG emissions means a gas stream containing fluorinated GHG which has exited the process (or process condenser or control condenser, where applicable), but which has not yet been introduced into a destruction device to reduce the mass of fluorinated GHG in the stream. If the emissions from the process are not routed to a destruction device, uncontrolled emissions are those fluorinated GHG emissions released to the atmosphere. Unsafe-to-monitor means that monitoring personnel would be exposed to an immediate danger as a consequence of monitoring the piece of equipment. Examples of unsafe-to-monitor equipment include, but are not limited to, equipment under extreme pressure or heat." 40:40:23.0.1.1.2.14.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.140 Definition of the source category.,EPA,,,,"(a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass. (b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart." 40:40:23.0.1.1.2.14.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.141 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either § 98.2(a)(1) or (2). 40:40:23.0.1.1.2.14.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.142 GHGs to report.,EPA,,,,"You must report: (a) CO 2 process emissions from each continuous glass melting furnace. (b) CO 2 combustion emissions from each continuous glass melting furnace. (c) CH 4 and N 2 O combustion emissions from each continuous glass melting furnace. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (d) CO 2 , CH 4 , and N 2 O emissions from each stationary fuel combustion unit other than continuous glass melting furnaces. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C." 40:40:23.0.1.1.2.14.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.143 Calculating GHG emissions.,EPA,,,"[75 FR 74831, Dec. 1, 2010, as amended at 78 FR 71954, Nov. 29, 2013]","You must calculate and report the annual process CO 2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) through (c) of this section. (a) For each continuous glass melting furnace 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 CO 2 emissions by operating and maintaining a CEMS to measure CO 2 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 (General Stationary Fuel Combustion Sources). (b) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 emissions from the glass melting furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraph (b)(2) of this section, except as specified in paragraph (c) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 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 (General Stationary Fuel Combustion Sources). (2) Calculate and report the process and combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section. (i) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the carbonate-based mineral mass fraction. (ii) Determine the quantity of each carbonate-based raw material charged to the furnace. (iii) Apply the appropriate emission factor for each carbonate-based raw material charged to the furnace, as shown in Table N-1 to this subpart. (iv) Use Equation N-1 of this section to calculate process mass emissions of CO 2 for each furnace: Where: E CO2 = Process emissions of CO 2 from the furnace (metric tons). n = Number of carbonate-based raw materials charged to furnace. MF i = Annual average decimal mass fraction of carbonate-based mineral i in carbonate-based raw material i. M i = Annual amount of carbonate-based raw material i charged to furnace (tons). 2000/2205 = Conversion factor to convert tons to metric tons. EF i = Emission factor for carbonate-based raw material i (metric ton CO 2 per metric ton carbonate-based raw material as shown in Table N-1 to this subpart). F i = Decimal fraction of calcination achieved for carbonate-based raw material i, assumed to be equal to 1.0. Where: E CO2 = Process emissions of CO 2 from the furnace (metric tons). n = Number of carbonate-based raw materials charged to furnace. MF i = Annual average decimal mass fraction of carbonate-based mineral i in carbonate-based raw material i. M i = Annual amount of carbonate-based raw material i charged to furnace (tons). 2000/2205 = Conversion factor to convert tons to metric tons. EF i = Emission factor for carbonate-based raw material i (metric ton CO 2 per metric ton carbonate-based raw material as shown in Table N-1 to this subpart). F i = Decimal fraction of calcination achieved for carbonate-based raw material i, assumed to be equal to 1.0. (v) You must calculate the total process CO 2 emissions from continuous glass melting furnaces at the facility using Equation N-2 of this section: Where: CO 2 = Annual process CO 2 emissions from glass manufacturing facility (metric tons). E CO2i = Annual CO 2 emissions from glass melting furnace i (metric tons). k = Number of continuous glass melting furnaces. Where: CO 2 = Annual process CO 2 emissions from glass manufacturing facility (metric tons). E CO2i = Annual CO 2 emissions from glass melting furnace i (metric tons). k = Number of continuous glass melting furnaces. (vi) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 emissions in the glass furnace according to the applicable requirements in subpart C. (c) As an alternative to data provided by the raw material supplier, a value of 1.0 can be used for the mass fraction (MF i ) of carbonate-based mineral i in Equation N-1 of this section." 40:40:23.0.1.1.2.14.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.144 Monitoring and QA/QC requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 78 FR 71954, Nov. 29, 2013; 81 FR 89257, Dec. 9, 2016]","(a) You must measure annual amounts of carbonate-based raw materials charged to each continuous glass melting furnace from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year. (b) Unless you use the default value of 1.0, you must measure carbonate-based mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis using consensus standards that specify X-ray fluorescence. For measurements made in years prior to the emissions reporting year 2014, you may also use ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes or 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 (both incorporated by reference, see § 98.7). (c) Unless you use the default value of 1.0, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis. (d) Unless you use the default value of 1.0, you must determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry consensus standard. If performed, this chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization ( e.g., ASTM, ASME, API, etc.)." 40:40:23.0.1.1.2.14.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.145 Procedures for estimating missing data.,EPA,,,,"A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbonate raw materials consumed, etc.). If the monitoring and quality assurance procedures in § 98.144 cannot be followed and data is missing, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such missing value estimates. (a) For missing data on the monthly amounts of carbonate-based raw materials charged to any continuous glass melting furnace 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. (b) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials assume that the mass fraction of each carbonate based mineral is 1.0." 40:40:23.0.1.1.2.14.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.146 Data reporting requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 78 FR 71954, Nov. 29, 2013; 79 FR 63786, Oct. 24, 2014; 81 FR 89257, Dec. 9, 2016; 89 FR 31925, Apr. 25, 2024]","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 CO 2 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 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 CO 2 emissions from continuous glass melting furnaces, and process CO 2 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 CO 2 (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)." 40:40:23.0.1.1.2.14.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.147 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71954, Nov. 29, 2013; 79 FR 63786, Oct. 24, 2014; 81 FR 89257, Dec. 9, 2016; 89 FR 31925, Apr. 25, 2024]","In addition to the information required by § 98.3(g), you must retain the records listed in paragraphs (a) through (d) of this section. (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 CO 2 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 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 CO 2 . (c) All other documentation used to support the reported GHG emissions. (d) Verification software records. 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 carbonate-based mineral in each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of § 98.143). (2) Annual amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons) (Equation N-1 of this subpart). (3) Decimal fraction of calcination achieved for each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of this subpart)." 40:40:23.0.1.1.2.14.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,N,Subpart N—Glass Production,,§ 98.148 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.15.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.150 Definition of the source category.,EPA,,,,"The HCFC-22 production and HFC-23 destruction source category consists of HCFC-22 production processes and HFC-23 destruction processes. (a) An HCFC-22 production process produces HCFC-22 (chlorodifluoromethane, or CHClF 2 ) from chloroform (CHCl 3 ) and hydrogen fluoride (HF). (b) An HFC-23 destruction process is any process in which HFC-23 undergoes destruction. An HFC-23 destruction process may or may not be co-located with an HCFC-22 production process at the same facility." 40:40:23.0.1.1.2.15.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.151 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains an HCFC-22 production or HFC-23 destruction process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). 40:40:23.0.1.1.2.15.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.152 GHGs to report.,EPA,,,,"(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C. (b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes." 40:40:23.0.1.1.2.15.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.153 Calculating GHG emissions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013]","(a) The mass of HFC-23 generated from each HCFC-22 production process shall be estimated by using one of two methods, as applicable: (1) Where the mass flow of the combined stream of HFC-23 and another reaction product (e.g., HCl) is measured, multiply the weekly (or more frequent) HFC-23 concentration measurement (which may be the average of more frequent concentration measurements) by the weekly (or more frequent) mass flow of the combined stream of HFC-23 and the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year. This calculation is summarized in Equation O-1 of this section: Where: G 23 = Mass of HFC-23 generated annually (metric tons). c 23 = Fraction HFC-23 by weight in HFC-23/other product stream. F p = Mass flow of HFC-23/other product stream during the period p (kg). p = Period over which mass flows and concentrations are measured. n = Number of concentration and flow measurement periods for the year. 10 −3 = Conversion factor from kilograms to metric tons. Where: G 23 = Mass of HFC-23 generated annually (metric tons). c 23 = Fraction HFC-23 by weight in HFC-23/other product stream. F p = Mass flow of HFC-23/other product stream during the period p (kg). p = Period over which mass flows and concentrations are measured. n = Number of concentration and flow measurement periods for the year. 10 −3 = Conversion factor from kilograms to metric tons. (2) Where the mass of only a reaction product other than HFC-23 (either HCFC-22 or HCl) is measured, multiply the ratio of the weekly (or more frequent) measurement of the HFC-23 concentration and the weekly (or more frequent) measurement of the other product concentration by the weekly (or more frequent) mass produced of the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year. This calculation is summarized in Equation O-2 of this section, assuming that the other product is HCFC-22. If the other product is HCl, HCl may be substituted for HCFC-22 in Equations O-2 and O-3 of this section. Where: G 23 = Mass of HFC-23 generated annually (metric tons). c 23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream. c 22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 stream. P 22 = Mass of HCFC-22 produced over the period p (kg), calculated using Equation O-3 of this section. p = Period over which masses and concentrations are measured. n = Number of concentration and mass measurement periods for the year. 10 −3 = Conversion factor from kilograms to metric tons. Where: G 23 = Mass of HFC-23 generated annually (metric tons). c 23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream. c 22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 stream. P 22 = Mass of HCFC-22 produced over the period p (kg), calculated using Equation O-3 of this section. p = Period over which masses and concentrations are measured. n = Number of concentration and mass measurement periods for the year. 10 −3 = Conversion factor from kilograms to metric tons. (b) The mass of HCFC-22 produced over the period p shall be estimated by using Equation O-3 of this section: Where: P 22 = Mass of HCFC-22 produced over the period p (kg). O 22 = mass of HCFC-22 that is measured coming out of the Production process over the period p (kg). U 22 = Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period p (kg). LF = Factor to account for the loss of HCFC-22 upstream of the measurement. The value for LF shall be determined pursuant to § 98.154(e). Where: P 22 = Mass of HCFC-22 produced over the period p (kg). O 22 = mass of HCFC-22 that is measured coming out of the Production process over the period p (kg). U 22 = Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period p (kg). LF = Factor to account for the loss of HCFC-22 upstream of the measurement. The value for LF shall be determined pursuant to § 98.154(e). (c) For HCFC-22 production facilities that do not use a destruction device or that have a destruction device that is not directly connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-4 of this section: Where: E 23 = Mass of HFC-23 emitted annually (metric tons). G 23 = Mass of HFC-23 generated annually (metric tons). S 23 = Mass of HFC-23 sent off site for sale annually (metric tons). OD 23 = Mass of HFC-23 sent off site for destruction (metric tons). D 23 = Mass of HFC-23 destroyed on site (metric tons). I 23 = Increase in HFC-23 inventory = HFC-23 in storage at end of year—HFC-23 in storage at beginning of year (metric tons). Where: E 23 = Mass of HFC-23 emitted annually (metric tons). G 23 = Mass of HFC-23 generated annually (metric tons). S 23 = Mass of HFC-23 sent off site for sale annually (metric tons). OD 23 = Mass of HFC-23 sent off site for destruction (metric tons). D 23 = Mass of HFC-23 destroyed on site (metric tons). I 23 = Increase in HFC-23 inventory = HFC-23 in storage at end of year—HFC-23 in storage at beginning of year (metric tons). (d) For HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-5 of this section: Where: E 23 = Mass of HFC-23 emitted annually (metric tons). E L = Mass of HFC-23 emitted annually from equipment leaks, calculated using Equation O-6 of this section (metric tons). E PV = Mass of HFC-23 emitted annually from process vents, calculated using Equation O-7 of this section (metric tons). E D = Mass of HFC-23 emitted annually from destruction device (metric tons), calculated using Equation O-8 of this section. Where: E 23 = Mass of HFC-23 emitted annually (metric tons). E L = Mass of HFC-23 emitted annually from equipment leaks, calculated using Equation O-6 of this section (metric tons). E PV = Mass of HFC-23 emitted annually from process vents, calculated using Equation O-7 of this section (metric tons). E D = Mass of HFC-23 emitted annually from destruction device (metric tons), calculated using Equation O-8 of this section. (1) The mass of HFC-23 emitted annually from equipment leaks (for use in Equation O-5 of this section) shall be estimated by using Equation O-6 of this section: Where: E L = Mass of HFC-23 emitted annually from equipment leaks (metric tons). c 23 = Fraction HFC-23 by weight in the stream(s) in the equipment. F Gt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value greater than or equal to 10,000 ppmv (kg/hr/source). N Gt = The number of sources of equipment type and service t with screening values greater than or equal to 10,000 ppmv as determined according to § 98.154(i). F Lt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value of less than 10,000 ppmv (kg/hr/source). N Lt = The number of sources of equipment type and service t with screening values less than 10,000 ppmv as determined according to § 98.154(j). p = One hour. n = Number of hours during the year during which equipment contained HFC-23. t = Equipment type and service as specified in Table O-1 of this subpart. 10 −3 = Factor converting kg to metric tons. Where: E L = Mass of HFC-23 emitted annually from equipment leaks (metric tons). c 23 = Fraction HFC-23 by weight in the stream(s) in the equipment. F Gt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value greater than or equal to 10,000 ppmv (kg/hr/source). N Gt = The number of sources of equipment type and service t with screening values greater than or equal to 10,000 ppmv as determined according to § 98.154(i). F Lt = The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value of less than 10,000 ppmv (kg/hr/source). N Lt = The number of sources of equipment type and service t with screening values less than 10,000 ppmv as determined according to § 98.154(j). p = One hour. n = Number of hours during the year during which equipment contained HFC-23. t = Equipment type and service as specified in Table O-1 of this subpart. 10 −3 = Factor converting kg to metric tons. (2) The mass of HFC-23 emitted annually from process vents (for use in Equation O-5 of this section) shall be estimated by using Equation O-7 of this section: Where: E PV = Mass of HFC-23 emitted annually from process vents (metric tons). ER T = The HFC-23 emission rate from the process vents during the period of the most recent test (kg/hr). PR p = The HCFC-22 production rate during the period p (kg/hr). PR T = The HCFC-22 production rate during the most recent test period (kg/hr). l p = The length of the period p (hours). 10 −3 = Factor converting kg to metric tons. n = The number of periods in a year. Where: E PV = Mass of HFC-23 emitted annually from process vents (metric tons). ER T = The HFC-23 emission rate from the process vents during the period of the most recent test (kg/hr). PR p = The HCFC-22 production rate during the period p (kg/hr). PR T = The HCFC-22 production rate during the most recent test period (kg/hr). l p = The length of the period p (hours). 10 −3 = Factor converting kg to metric tons. n = The number of periods in a year. (3) The total mass of HFC-23 emitted from destruction devices shall be estimated by using Equation O-8 of this section: Where: E D = Mass of HFC-23 emitted annually from the destruction device (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). D 23 = Mass of HFC-23 destroyed annually (metric tons). Where: E D = Mass of HFC-23 emitted annually from the destruction device (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). D 23 = Mass of HFC-23 destroyed annually (metric tons). (4) For facilities that destroy HFC-23, the total mass of HFC-23 destroyed shall be estimated by using Equation O-9 of this section: Where: D 23 . = Mass of HFC-23 destroyed annually (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). DE = Destruction Efficiency of the destruction device (fraction). Where: D 23 . = Mass of HFC-23 destroyed annually (metric tons). F D = Mass of HFC-23 fed into the destruction device annually (metric tons). DE = Destruction Efficiency of the destruction device (fraction)." 40:40:23.0.1.1.2.15.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.154 Monitoring and QA/QC requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 78 FR 71955, Nov. 29, 2013]","These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to § 98.153. (a) The concentrations (fractions by weight) of HFC-23 and HCFC-22 in the product stream shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. (b) The mass flow of the product stream containing the HFC-23 shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (c) The mass of HCFC-22 or HCl coming out of the production process shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (d) The mass of any used HCFC-22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the mass in paragraph (c) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be considered used fluorinated HCFC-22 for purposes of this paragraph (d) of this section and § 98.153(b). (e) The loss factor LF in Equation O-3 of this subpart for the mass of HCFC-22 produced shall have the value 1.015 or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of HCFC-22 between the reactor and the point of measurement at the facility where production is being estimated. (f) The mass of HFC-23 sent off site for sale shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (g) The mass of HFC-23 sent off site for destruction shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentration of the fluorinated GHG shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 sent to another facility for destruction. (h) The masses of HFC-23 in storage at the beginning and end of the year shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. (i) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as follows: (1) A leak source that could emit HFC-23, and (2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured. (j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (i) of this section. (k) The mass of HFC-23 emitted from process vents shall be estimated at least monthly by incorporating the results of the most recent emissions test into Equation O-7 of this subpart. HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment shall conduct emissions tests at process vents at least once every five years or after significant changes to the process. Emissions tests shall be conducted in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall be sufficient to detect an emission rate that would result in annual emissions of 200 kg of HFC-23 if sustained over one year. (l) For purposes of Equation O-9 of this subpart, the destruction efficiency must be equated to the destruction efficiency determined during a new or previous performance test of the destruction device. HFC-23 destruction facilities shall conduct annual measurements of HFC-23 concentrations at the outlet of the destruction device in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall be taken under conditions that are typical for the production process and destruction device at the facility, and the average concentration of HFC-23 shall be determined. The sensitivity of the concentration measurement shall be sufficient to detect an outlet concentration equal to or less than the outlet concentration determined in the destruction efficiency performance test. If the concentration measurement indicates that the HFC-23 concentration is less than or equal to that measured during the performance test that is the basis for the destruction efficiency, continue to use the previously determined destruction efficiency. If the concentration measurement indicates that the HFC-23 concentration is greater than that measured during the performance test that is the basis for the destruction efficiency, facilities shall either: (1) Substitute the higher HFC-23 concentration for that measured during the destruction efficiency performance test and calculate a new destruction efficiency, or (2) Estimate the mass emissions of HFC-23 from the destruction device based on the measured HFC-23 concentration and volumetric flow rate determined by measurement of volumetric flow rate using EPA Method 2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40 CFR part 60, appendix A-2. Determine the mass rate of HFC-23 into the destruction device by measuring the HFC-23 concentration and volumetric flow rate at the inlet or by a metering device for HFC-23 sent to the device. Determine a new destruction efficiency based on the mass flow rate of HFC-23 into and out of the destruction device. (m) HCFC-22 production facilities shall account for HFC-23 generation and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC-23 generation and emissions during these events, or documenting that these events do not result in significant HFC-23 generation and/or emissions. (n) The mass of HFC-23 fed into the destruction device shall be measured at least weekly using flow meters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentrations of the HFC-23 shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 destroyed. (o) In their estimates of the mass of HFC-23 destroyed, HFC-23 destruction facilities shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in State or local permitting requirements and/or destruction device manufacturer specifications. (p) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. (q) All gas chromatographs used to determine the concentration of HFC-23 in process streams shall be calibrated at least monthly through analysis of certified standards (or of calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Method 205 at 40 CFR part 51, appendix M) with known HFC-23 concentrations that are in the same range (fractions by mass) as the process samples." 40:40:23.0.1.1.2.15.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.155 Procedures for estimating missing data.,EPA,,,,"(a) 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 (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements: (1) For each missing value of the HFC-23 or HCFC-22 concentration, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product measurement where such a measurement is available. If that measurement is taken significantly downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device." 40:40:23.0.1.1.2.15.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.156 Data reporting requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 78 FR 71955, Nov. 29, 2013; 79 FR 63786, Oct. 24, 2014; 81 FR 89257, Dec. 9, 2016]","(a) In addition to the information required by § 98.3(c), the HCFC-22 production facility shall report the following information for each HCFC-22 production process: (1) Annual mass of HCFC-22 produced in metric tons. (2) [Reserved] (3) Annual mass of reactants fed into the process in metric tons of reactant. (4) The mass (in metric tons) of materials other than HCFC-22 and HFC-23 (i.e., unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and that are permanently removed from the process. (5) The method for tracking startups, shutdowns, and malfunctions and HFC-23 generation/emissions during these events. (6) The names and addresses of facilities to which any HFC-23 was sent for destruction, and the quantities of HFC-23 (metric tons) sent to each. (7)-(10) [Reserved] (11) Annual mass of HFC-23 emitted in metric tons. (12) Annual mass of HFC-23 emitted from equipment leaks in metric tons. (13) Annual mass of HFC-23 emitted from process vents in metric tons. (b) In addition to the information required by § 98.3(c), facilities that destroy HFC-23 shall report the following for each HFC-23 destruction process: (1)-(2) [Reserved] (3) Annual mass of HFC-23 emitted from the destruction device. (c) Each HFC-23 destruction facility shall report the concentration (mass fraction) of HFC-23 measured at the outlet of the destruction device during the facility's annual HFC-23 concentration measurements at the outlet of the device. If the concentration of HFC-23 is below the detection limit of the measuring device, report the detection limit and that the concentration is below the detection limit. (d) If the HFC-23 concentration measured pursuant to § 98.154(l) is greater than that measured during the performance test that is the basis for the destruction efficiency (DE), the facility shall report the method used to calculate the revised destruction efficiency, specifying whether § 98.154(l)(1) or (2) has been used for the calculation. (e) By March 31, 2011 or within 60 days of commencing HFC-23 destruction, HFC-23 destruction facilities shall submit a one-time report including the following information for each destruction process: (1) [Reserved] (2) The methods used to determine destruction efficiency. (3) The methods used to record the mass of HFC-23 destroyed. (4) The name of other relevant federal or state regulations that may apply to the destruction process. (5) If any changes are made that affect HFC-23 destruction efficiency or the methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change." 40:40:23.0.1.1.2.15.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.157 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 79 FR 63786, Oct. 24, 2014]","(a) In addition to the data required by § 98.3(g), HCFC-22 production facilities shall retain the following records: (1) The data used to estimate HFC-23 emissions. (2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to § 98.154(p) and (q). (b) In addition to the data required by § 98.3(g), the HFC-23 destruction facilities shall retain the following records: (1) Records documenting their one-time and annual reports in § 98.156(b) through (e). (2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this subpart, including the industry standard practice or manufacturer directions used for calibration pursuant to § 98.154(p) and (q). (c) Verification software records. 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 (c)(1) through (16) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (16) of this section. (1) Factor to account for the loss of HCFC-22 upstream of the measurement over the period, determined pursuant to § 98.154(e) (Equation O-3 of § 98.153). (2) Mass of HCFC-22 that is measured coming out of the production process over the period. A period can be one year (kg) (Equation O-3). (3) Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period. A period can be one year (kg) (Equation O-3). (4) Mass of HFC-23 generated annually per HCFC-22 production process (metric tons) (Equation O-4 of § 98.153). (5) Mass of HFC-23 sent off site for sale annually per HCFC-22 production process (metric tons) (Equation O-4). (6) Mass of HFC-23 sent off site for destruction annually per HCFC-22 production process (metric tons) (Equation O-4). (7) Mass of HFC-23 destroyed on site per HCFC-22 production process (metric tons) (Equation O-4). (8) HFC-23 in storage at end of year per HCFC-22 production process (metric tons) (Equation O-4). (9) HFC-23 in storage at beginning of year per HCFC-22 production process (metric tons) (Equation O-4). (10) Mass of HFC-23 fed into each destruction device annually per HCFC-22 production process (metric tons) (Equation O-9 of § 98.153 and the calculation method in either § 98.154(l)(1) or (2)). (11) Identify if each destruction efficiency for each HCFC-22 production process is entered directly, or is calculated using § 98.154(l)(1), or is calculated using § 98.154(l)(2) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)). (12) Destruction efficiency of each destruction device for each HCFC-22 production process (decimal fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)). (13) Volumetric flow rate at the inlet of each destruction device for each HCFC-22 production process from previous test (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)). (14) Volumetric flow rate at the inlet of destruction device during test for each HCFC-22 production process (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)). (15) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process from previous test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)). (16) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process during test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2))." 40:40:23.0.1.1.2.15.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,O,Subpart O—HCFC-22 Production and HFC-23 Destruction,,§ 98.158 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.16.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.160 Definition of the source category.,EPA,,,"[89 FR 31925, Apr. 25, 2024]","(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 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)." 40:40:23.0.1.1.2.16.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.161 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). 40:40:23.0.1.1.2.16.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.162 GHGs to report.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 89 FR 31926, Apr. 25, 2024]","You must report: (a) CO 2 emissions from each hydrogen production process unit, including fuel combustion emissions accounted for in the calculation methodologies in § 98.163. (b) [Reserved] (c) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than hydrogen production process units. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (d) For CO 2 collected and transferred off site, you must follow the requirements of subpart PP of this part." 40:40:23.0.1.1.2.16.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.163 Calculating GHG emissions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 75 FR 79157, Dec. 17, 2010; 78 FR 71955, Nov. 29, 2013; 81 FR 89257, Dec. 9, 2016; 89 FR 31926, Apr. 25, 2024]","You must calculate and report the annual CO 2 emissions from each hydrogen production process unit using the procedures specified in paragraphs (a) through (c) of this section, as applicable. (a) Continuous Emissions Monitoring Systems (CEMS). Calculate and report under this subpart the CO 2 emissions by operating and maintaining CEMS 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 (General Stationary Fuel Combustion Sources). (b) Fuel and feedstock material balance approach. Calculate and report CO 2 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. (1) Gaseous fuel and feedstock. You must calculate the annual CO 2 emissions from each gaseous fuel and feedstock according to Equation P-1 of this section: Where: CO 2 = Annual CO 2 process emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = Volume or mass of the gaseous fuel or feedstock used in month n (scf (at standard conditions of 68 °F and atmospheric pressure) or kg of fuel or feedstock). CC n = Average carbon content of the gaseous fuel or feedstock for month n (kg carbon per kg of fuel or feedstock). MW n = Average molecular weight of the gaseous fuel or feedstock for month n (kg/kg-mole). If you measure mass, the term “MW n /MVC” is replaced with “1”. MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. Where: CO 2 = Annual CO 2 process emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = Volume or mass of the gaseous fuel or feedstock used in month n (scf (at standard conditions of 68 °F and atmospheric pressure) or kg of fuel or feedstock). CC n = Average carbon content of the gaseous fuel or feedstock for month n (kg carbon per kg of fuel or feedstock). MW n = Average molecular weight of the gaseous fuel or feedstock for month n (kg/kg-mole). If you measure mass, the term “MW n /MVC” is replaced with “1”. MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. (2) Liquid fuel and feedstock. You must calculate the annual CO 2 emissions from each liquid fuel and feedstock according to Equation P-2 of this section: Where: CO 2 = Annual CO 2 emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = Volume or mass of the liquid fuel or feedstock used in month n (gallons or kg of fuel or feedstock). CC n = Average carbon content of the liquid fuel or feedstock, for month n (kg carbon per gallon or kg of fuel or feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. Where: CO 2 = Annual CO 2 emissions arising from fuel and feedstock consumption (metric tons/yr). Fdstk n = Volume or mass of the liquid fuel or feedstock used in month n (gallons or kg of fuel or feedstock). CC n = Average carbon content of the liquid fuel or feedstock, for month n (kg carbon per gallon or kg of fuel or feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. (3) Solid fuel and feedstock. You must calculate the annual CO 2 emissions from each solid fuel and feedstock according to Equation P-3 of this section: Where: CO 2 = Annual CO 2 emissions from fuel and feedstock consumption (metric tons/yr). Fdstk n = Mass of solid fuel or feedstock used in month n (kg of fuel or feedstock). CC n = Average carbon content of the solid fuel or feedstock, for month n (kg carbon per kg of fuel or feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. Where: CO 2 = Annual CO 2 emissions from fuel and feedstock consumption (metric tons/yr). Fdstk n = Mass of solid fuel or feedstock used in month n (kg of fuel or feedstock). CC n = Average carbon content of the solid fuel or feedstock, for month n (kg carbon per kg of fuel or feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 to carbon. 0.001 = Conversion factor from kg to metric tons. (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 CO 2 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 CO 2 emissions from fuel combustion related to the hydrogen production unit." 40:40:23.0.1.1.2.16.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.164 Monitoring and QA/QC requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71955, Nov. 29, 2013; 81 FR 89257, Dec. 9, 2016; 89 FR 31926, Apr. 25, 2024]","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: (a) If a CEMS is used to measure GHG emissions, then the facility must comply with the monitoring and QA/QC procedures specified in § 98.34(c). (b) If a CEMS is not used to measure GHG emissions, then you must: (1) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous fuel and feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to § 98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in § 98.3(i). (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 § 98.3(g)(5). (i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7). (ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7). (iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see § 98.7). (iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see § 98.7). (v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see § 98.7). (vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7). (vii) 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 (incorporated by reference, see § 98.7). (viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7). (ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7). (x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7). (xi) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7). (xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal (incorporated by reference, see § 98.7). (xiii) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles (incorporated by reference, see § 98.7). (xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see § 98.7). (xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7). (xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7). (xvii) ISO 3170: Petroleum Liquids—Manual sampling—Third Edition (incorporated by reference, see § 98.7). (xviii) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition (incorporated by reference, see § 98.7). (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 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." 40:40:23.0.1.1.2.16.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.165 Procedures for estimating missing data.,EPA,,,,"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 (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this section: (a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen production, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates. (b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality-assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates. (c) For missing CEMS data, you must use the missing data procedures in § 98.35." 40:40:23.0.1.1.2.16.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.166 Data reporting requirements.,EPA,,,"[89 FR 31927, Apr. 25, 2024]","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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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., 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)." 40:40:23.0.1.1.2.16.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.167 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71956, Nov. 29, 2013; 79 FR 63787, Oct. 24, 2014; 89 FR 31927, Apr. 25, 2024]","In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each hydrogen production facility. (a) If a CEMS is used to measure CO 2 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 CO 2 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). (c) [Reserved] (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. (1) Indicate whether the monthly consumption of each gaseous fuel or feedstock is measured as mass or volume (Equation P-1 of § 98.163). (2) Monthly volume of the gaseous fuel or feedstock (scf at standard conditions of 68 °F and atmospheric pressure) (Equation P-1). (3) Monthly mass of the gaseous fuel or feedstock (kg of fuel or feedstock) (Equation P-1). (4) Average monthly carbon content of the gaseous fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-1). (5) Average monthly molecular weight of the gaseous fuel or feedstock (kg/kg-mole) (Equation P-1). (6) Indicate whether the monthly consumption of each liquid fuel or feedstock is measured as mass or volume (Equation P-2 of § 98.163). (7) Monthly volume of the liquid fuel or feedstock (gallons of fuel or feedstock) (Equation P-2). (8) Monthly mass of the liquid fuel or feedstock (kg of fuel or feedstock) (Equation P-2). (9) Average monthly carbon content of the liquid fuel or feedstock (kg C per gallon of fuel or feedstock) (Equation P-2). (10) Average monthly carbon content of the liquid fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-2). (11) Monthly mass of solid fuel or feedstock (kg of fuel and feedstock) (Equation P-3 of § 98.163). (12) Average monthly carbon content of the solid fuel or feedstock (kg C per kg of fuel and feedstock) (Equation P-3)." 40:40:23.0.1.1.2.16.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,P,Subpart P—Hydrogen Production,,§ 98.168 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.17.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.170 Definition of the source category.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013]","The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not collocated with an integrated iron and steel manufacturing process, direct reduction furnaces not collocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not collocated with an integrated iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility." 40:40:23.0.1.1.2.17.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.171 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either § 98.2(a)(1) or (2). 40:40:23.0.1.1.2.17.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.172 GHGs to report.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010]","(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 , CH 4 , and N 2 O from each stationary combustion unit following the requirements of subpart C except for flares. Stationary combustion units include, but are not limited to, by-product recovery coke oven battery combustion stacks, blast furnace stoves, boilers, process heaters, reheat furnaces, annealing furnaces, flame suppression, ladle reheaters, and other miscellaneous combustion sources. (b) You must report CO 2 emissions from flares that burn blast furnace gas or coke oven gas according to the procedures in § 98.253(b)(1) of subpart Y (Petroleum Refineries) of this part. When using the alternatives set forth in § 98.253(b)(1)(ii)(B) and § 98.253(b)(1)(iii)(C), you must use the default CO 2 emission factors for coke oven gas and blast furnace gas from Table C-1 to subpart C in Equations Y-2 and Y-3 of subpart Y. You must report CH 4 and N 2 O emissions from flares according to the requirements in § 98.33(c)(2) using the emission factors for coke oven gas and blast furnace gas in Table C-2 to subpart C of this part. (c) You must report process CO 2 emissions from each taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery combustion stack; coke pushing process; sinter process; EAF; decarburization vessel; and direct reduction furnace by following the procedures in this subpart." 40:40:23.0.1.1.2.17.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.173 Calculating GHG emissions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71956, Nov. 29, 2013; 81 FR 89258, Dec. 9, 2016; 89 FR 31928, Apr. 25, 2024]","You must calculate and report the annual process CO 2 emissions from each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, and direct reduction furnace using the procedures in either paragraph (a) or (b) of this section. Calculate and report the annual process CO 2 emissions from the coke pushing process according to paragraph (c) of this section. (a) Calculate and report under this subpart the process CO 2 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 (General Stationary Fuel Combustion Sources). (b) Calculate and report under this subpart the process CO 2 emissions using the procedure in paragraph (b)(1) or (b)(2) of this section. (1) Carbon mass balance method. Calculate the annual mass emissions of CO 2 for the process as specified in paragraphs (b)(1)(i) through (b)(1)(vii) of this section. The calculations are based on the annual mass of inputs and outputs to the process and an annual analysis of the respective weight fraction of carbon as determined according to the procedures in § 98.174(b). If you have a process input or output other than CO 2 in the exhaust gas that contains carbon that is not included in Equations Q-1 through Q-7 of this section, you must account for the carbon and mass rate of that process input or output in your calculations according to the procedures in § 98.174(b)(5). (i) For taconite indurating furnaces, estimate CO 2 emissions using Equation Q-1 of this section. Where: CO 2 = Annual CO 2 mass emissions from the taconite indurating furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F s ) = Annual mass of the solid fuel used (metric tons). (C sf ) = Carbon content of the solid fuel, from the fuel analysis (expressed as a decimal fraction). (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (F l ) = Annual volume of the liquid fuel used (gallons). (C lf ) = Carbon content of the liquid fuel, from the fuel analysis results (kg C per gallon of fuel). (O) = Annual mass of greenball (taconite) pellets fed to the furnace (metric tons). (C 0 ) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction). (P) = Annual mass of fired pellets produced by the furnace (metric tons). (C p ) = Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the taconite indurating furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F s ) = Annual mass of the solid fuel used (metric tons). (C sf ) = Carbon content of the solid fuel, from the fuel analysis (expressed as a decimal fraction). (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (F l ) = Annual volume of the liquid fuel used (gallons). (C lf ) = Carbon content of the liquid fuel, from the fuel analysis results (kg C per gallon of fuel). (O) = Annual mass of greenball (taconite) pellets fed to the furnace (metric tons). (C 0 ) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction). (P) = Annual mass of fired pellets produced by the furnace (metric tons). (C p ) = Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (ii) For basic oxygen process furnaces, estimate CO 2 emissions using Equation Q-2 of this section. Where: CO 2 = Annual CO 2 mass emissions from the basic oxygen furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of molten iron charged to the furnace (metric tons). (C Iron ) = Carbon content of the molten iron, from the carbon analysis results (expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction), Where: CO 2 = Annual CO 2 mass emissions from the basic oxygen furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of molten iron charged to the furnace (metric tons). (C Iron ) = Carbon content of the molten iron, from the carbon analysis results (expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction). (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction), (iii) For non-recovery coke oven batteries, estimate CO 2 emissions using Equation Q-3 of this section. Where: CO 2 = Annual CO 2 mass emissions from the non-recovery coke oven battery (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Coal) = Annual mass of coal charged to the battery (metric tons). (C Coal ) = Carbon content of the coal, from the carbon analysis results (expressed as a decimal fraction). (Coke) = Annual mass of coke produced by the battery (metric tons). (C Coke ) = Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the non-recovery coke oven battery (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Coal) = Annual mass of coal charged to the battery (metric tons). (C Coal ) = Carbon content of the coal, from the carbon analysis results (expressed as a decimal fraction). (Coke) = Annual mass of coke produced by the battery (metric tons). (C Coke ) = Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (iv) For sinter processes, estimate CO 2 emissions using Equation Q-4 of this section. Where: CO 2 = Annual CO 2 mass emissions from the sinter process (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (Feed) = Annual mass of sinter feed material (metric tons). (C Feed ) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressed as a decimal fraction). (Sinter) = Annual mass of sinter produced (metric tons). (C Sinter ) = Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the sinter process (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (Feed) = Annual mass of sinter feed material (metric tons). (C Feed ) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressed as a decimal fraction). (Sinter) = Annual mass of sinter produced (metric tons). (C Sinter ) = Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (v) For EAFs, estimate CO 2 emissions using Equation Q-5 of this section. Where: CO 2 = Annual CO 2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (C Iron ) = Carbon content of the direct reduced iron, from the carbon analysis results (expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (Flux) = Annual mass of flux materials ( e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (Electrode) = Annual mass of carbon electrode consumed (metric tons). (C Electrode ) = Carbon content of the carbon electrode, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials ( e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction). (F g ) = Annual volume of the gaseous fuel used (scf at 60 degrees F and one atmosphere). (C gf ) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). (MW) = Molecular weight of the gaseous fuel (kg/kg-mole). (MVC) = Molar volume conversion factor (836.6 scf per kg-mole at standard conditions of 60 degrees F and one atmosphere). (0.001) = Conversion factor from kg to metric tons. (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the EAF (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (C Iron ) = Carbon content of the direct reduced iron, from the carbon analysis results (expressed as a decimal fraction). (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap ) = Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction). (Flux) = Annual mass of flux materials ( e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux ) = Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction). (Electrode) = Annual mass of carbon electrode consumed (metric tons). (C Electrode ) = Carbon content of the carbon electrode, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials ( e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel ) = Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction). (F g ) = Annual volume of the gaseous fuel used (scf at 60 degrees F and one atmosphere). (C gf ) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). (MW) = Molecular weight of the gaseous fuel (kg/kg-mole). (MVC) = Molar volume conversion factor (836.6 scf per kg-mole at standard conditions of 60 degrees F and one atmosphere). (0.001) = Conversion factor from kg to metric tons. (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag ) = Carbon content of the slag, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (vi) For decarburization vessels, estimate CO 2 emissions using Equation Q-6 of this section. Where: CO 2 = Annual CO 2 mass emissions from the decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Steel) = Annual mass of molten steel charged to the vessel (metric tons). (C Steelin ) = Carbon content of the molten steel before decarburization, from the carbon analysis results (expressed as a decimal fraction). (C Steelout ) = Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (Steel) = Annual mass of molten steel charged to the vessel (metric tons). (C Steelin ) = Carbon content of the molten steel before decarburization, from the carbon analysis results (expressed as a decimal fraction). (C Steelout ) = Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (vii) For direct reduction furnaces, estimate CO 2 emissions using Equation Q-7 of this section. Where: CO 2 = Annual CO 2 mass emissions from the direct reduction furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace (metric tons). (C Ore ) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Other) = Annual mass of other materials charged to the furnace (metric tons). (C Other ) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction). (Iron) = Annual mass of iron produced (metric tons). (C Iron ) = Carbon content of the iron, from the carbon analysis results (expressed as a decimal fraction). (NM) = Annual mass of non-metallic materials produced by the furnace (metric tons). (C NM ) = Carbon content of the non-metallic materials, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). Where: CO 2 = Annual CO 2 mass emissions from the direct reduction furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. (F g ) = Annual volume of the gaseous fuel used (scf). (C gf ) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel). MW = Molecular weight of the gaseous fuel (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons. (Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace (metric tons). (C Ore ) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (expressed as a decimal fraction). (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon ) = Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction). (Other) = Annual mass of other materials charged to the furnace (metric tons). (C Other ) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction). (Iron) = Annual mass of iron produced (metric tons). (C Iron ) = Carbon content of the iron, from the carbon analysis results (expressed as a decimal fraction). (NM) = Annual mass of non-metallic materials produced by the furnace (metric tons). (C NM ) = Carbon content of the non-metallic materials, from the carbon analysis results (expressed as a decimal fraction). (R) = Annual mass of air pollution control residue collected (metric tons). (C R ) = Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction). (2) Site-specific emission factor method. Conduct a performance test and measure CO 2 emissions from all exhaust stacks for the process and measure either the feed rate of materials into the process or the production rate during the test as described in paragraphs (b)(2)(i) through (b)(2)(iv) of this section. (i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in § 98.174(c)(5) and calculate the average rate for the test period in metric tons per hour. (ii) You must calculate the hourly CO 2 emission rate using Equation Q-8 of this section and determine the average hourly CO 2 emission rate for the test. Where: CO 2 = CO 2 mass emission rate, corrected for moisture (metric tons/hr). 5.18 × 10 −7 = Conversion factor (metric tons/scf−% CO 2 ). C CO2 = Hourly CO 2 concentration, dry basis (% CO 2 ). Q = Hourly stack gas volumetric flow rate (scfh). %H 2 O = Hourly moisture percentage in the stack gas. Where: CO 2 = CO 2 mass emission rate, corrected for moisture (metric tons/hr). 5.18 × 10 −7 = Conversion factor (metric tons/scf−% CO 2 ). C CO2 = Hourly CO 2 concentration, dry basis (% CO 2 ). Q = Hourly stack gas volumetric flow rate (scfh). %H 2 O = Hourly moisture percentage in the stack gas. (iii) You must calculate a site-specific emission factor for the process in metric tons of CO 2 per metric ton of feed or production, as applicable, by dividing the average hourly CO 2 emission rate during the test by the average hourly feed or production rate during the test. (iv) You must calculate CO 2 emissions for the process by multiplying the emission factor by the total amount of feed or production, as applicable, for the reporting period. (c) You must determine emissions of CO 2 from the coke pushing process in mtCO 2 e by multiplying the metric tons of coal charged to the by-product recovery and non-recovery coke ovens during the reporting period by 0.008. (d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented through a stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO 2 emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. 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 comply with all associated requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources)." 40:40:23.0.1.1.2.17.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.174 Monitoring and QA/QC requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71957, Nov. 29, 2013; 89 FR 31928, Apr. 25, 2024]","(a) If you operate and maintain a CEMS that measures CO 2 emissions consistent with subpart C of this part, you must meet the monitoring and QA/QC requirements of § 98.34(c). (b) If you determine CO 2 emissions using the carbon mass balance procedure in § 98.173(b)(1), you must: (1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in § 98.34. No determination of the mass of steel output from decarburization vessels is required. (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 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. (i) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for limestone, dolomite, and slag. (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7) for coal, coke, and other carbonaceous materials. (iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry (incorporated by reference, see § 98.7) for iron ore, taconite pellets, and other iron-bearing materials. (iv) 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 (incorporated by reference, see § 98.7) for iron and ferrous scrap. (v) ASM CS-104 UNS No. G10460—Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference, see § 98.7); ISO/CSAPR 15349-1:1998, Unalloyed steel—Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15) First Edition (incorporated by reference, see § 98.7); or ISO/CSAPR 15349-3:1998, Unalloyed steel-Determination of low carbon content Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15) First Edition (incorporated by reference, see § 98.7) as applicable for steel. (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. (vii) For each process input that is a fuel, determine the carbon content and molecular weight (if applicable) using the applicable methods listed in § 98.34. (3) For solid ferrous materials charged to basic oxygen process furnaces or EAFs that differ in carbon content, you may determine a weighted average carbon content based on the carbon content of each type of ferrous material and the average weight percent of each type that is used. Examples of these different ferrous materials include carbon steel, low carbon steel, stainless steel, high alloy steel, pig iron, iron scrap, and direct reduced iron. (4) 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. (5) Except as provided in paragraph (b)(4) of this section, you must determine the annual carbon content and monthly mass rate of any input or output that contains carbon that is not listed in the equations in § 98.173(b)(1) using the procedures in paragraphs (b)(1) and (b)(2) of this section. (c) If you determine CO 2 emissions using the site-specific emission factor procedure in § 98.173(b)(2), you must: (1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process. (2)(i) For the exhaust from basic oxygen furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel. (ii) For the exhaust from continuously charged EAFs, sample the exhaust for a period spanning at least three hours. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel. (3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 3 hours. (4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO 2 concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate, and Method 4 at 40 CFR part 60, at appendix A-3 to determine the moisture content of the stack gas. (5) Determine the mass rate of process feed or process production (as applicable) during the test using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of bulk density and volume measurements, etc.) (6) If your process operates under different conditions as part of normal operations in such a manner that CO 2 emissions change by more than 20 percent (e.g., routine changes in the carbon content of the sinter feed or change in grade of product), you must perform emission testing and develop separate emission factors for these different operating conditions and determine emissions based on the number of hours the process operates and the production or feed rate (as applicable) at each specific different condition. (7) If your EAF and decarburization vessel exhaust to a common emission control device and stack, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when both processes are operating and base the site-specific emission factor on the steel production rate of the EAF. (8) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must contain all information and data used to derive the emission factor. (d) For a coke pushing process, determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density." 40:40:23.0.1.1.2.17.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.175 Procedures for estimating missing data.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013]","A complete record of all measured parameters used in the GHG emissions calculations in § 98.173 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must follow the missing data procedures in § 98.255(b) of subpart Y (Petroleum Refineries) of this part for flares burning coke oven gas or blast furnace gas. You must document and keep records of the procedures used for all such estimates. (a) Except as provided in § 98.174(b)(4), 100 percent data availability is required for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in § 98.173(b)(1) or facilities that estimate emissions using the site-specific emission factor procedure in § 98.173(b)(2). (b) For missing records of the monthly mass or volume of carbon-containing inputs and outputs using the carbon mass balance procedure in § 98.173(b)(1), the substitute data value must be based on the best available estimate of the mass of the input or output material from all available process data or data used for accounting purposes." 40:40:23.0.1.1.2.17.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.176 Data reporting requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013; 79 FR 63787, Oct. 24, 2014; 81 FR 89258, Dec. 9, 2016; 89 FR 31928, Apr. 25, 2024]","In addition to the information required by § 98.3(c), each annual report must contain the information required in paragraphs (a) through (h) of this section for each coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; sinter process; EAF; decarburization vessel; direct reduction furnace; and flare burning coke oven gas or blast furnace gas. For reporting year 2010, the information required in paragraphs (a) through (h) of this section is not required for decarburization vessels that are not argon-oxygen decarburization vessels. For reporting year 2011 and each subsequent reporting year, the information in paragraphs (a) through (h) of this section must be reported for all decarburization vessels. (a) Unit identification number and annual CO 2 emissions (in metric tons). (b) If a CEMS is used to measure CO 2 emissions, then you must report the annual production quantity for the production unit (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel. (c) If a CEMS is used to measure CO 2 emissions, then you must report the relevant information required under § 98.36 for the Tier 4 Calculation Methodology. (d) If a CEMS is not used to measure CO 2 emissions, then you must report for each process whether the emissions were determined using the carbon mass balance method in § 98.173(b)(1) or the site-specific emission factor method in § 98.173(b)(2). (e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO 2 emissions, you must, except as provided in § 98.174(b)(4), report the following information for each process: (1) [Reserved] (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). (3)-(4) [Reserved] (5) If you used the missing data procedures in § 98.175(b), you must report how the monthly mass for each process input or output with missing data was determined and the number of months the missing data procedures were used. (6) The information specified in paragraphs (e)(6)(i) through (vi) of this section aggregated for all process units for which CO 2 emissions were determined using the mass balance method in § 98.173(b)(1), except as provided in § 98.174(b)(4). (i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used in process units for which CO 2 emissions were determined using Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-9 of this section. Where: Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process units (metric tons). n = Number of process units where fuel is used. F g,i = Annual volume of gaseous fuel combusted (“(F g )” in Equations Q-1, Q-4 and Q-7 of § 98.173) for each process (scf). MW i = Molecular weight of gaseous fuel used in each process (kg/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 scf per kg mole if you select 60 °F as standard temperature. F l,i = Annual volume of the liquid fuel combusted (“(F l )” included in Equation Q-1) for each process unit (gallons). F s,i = Annual mass of the solid fuel combusted (“(F s )” in Equation Q-1) for each process unit (metric tons). ρ l,i = Density of the liquid fuel (kg/gallon). 0.001 = Conversion factor from kg to metric tons. Where: Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process units (metric tons). n = Number of process units where fuel is used. F g,i = Annual volume of gaseous fuel combusted (“(F g )” in Equations Q-1, Q-4 and Q-7 of § 98.173) for each process (scf). MW i = Molecular weight of gaseous fuel used in each process (kg/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 scf per kg mole if you select 60 °F as standard temperature. F l,i = Annual volume of the liquid fuel combusted (“(F l )” included in Equation Q-1) for each process unit (gallons). F s,i = Annual mass of the solid fuel combusted (“(F s )” in Equation Q-1) for each process unit (metric tons). ρ l,i = Density of the liquid fuel (kg/gallon). 0.001 = Conversion factor from kg to metric tons. (ii) The annual mass (metric tons) of all non-fuel material inputs (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-10 of this section. Where: NFI = Annual mass of all non-fuel inputs (to all process unit types) specified in Equations Q-1 through Q-7 of § 98.173 (metric tons). n = Number of process units, all process types. O = Annual mass of greenball (taconite) pellets fed to the taconite furnace(s) (metric tons). Iron = Annual mass of molten iron charged to the basic oxygen furnace(s) plus annual mass of direct reduced iron charged to the EAF(s) (metric tons). Scrap = Annual mass of ferrous scrap charged to the basic oxygen furnace(s) and EAF(s) (metric tons). Flux = Annual mass of flux materials charged to the basic oxygen furnace(s) and EAF(s) (metric tons). Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the basic oxygen furnace(s), EAF(s), and direct reduction furnace(s) (metric tons). Coal = Annual mass of coal charged to the coke oven battery(s) (metric tons). Feed = Annual mass of sinter feed material charged to the sinter process(es) (metric tons). Electrode = Annual mass of carbon electrode consumed in the EAF(s) (metric tons). Steel in = Annual mass of molten steel charged to the decarburization vessels (metric tons). Ore = Annual mass of iron ore or iron ore pellets fed to the direct reduction furnace(s) (metric tons). Other = Annual mass of other materials charged to the direction reduction furnace(s) (metric tons). Where: NFI = Annual mass of all non-fuel inputs (to all process unit types) specified in Equations Q-1 through Q-7 of § 98.173 (metric tons). n = Number of process units, all process types. O = Annual mass of greenball (taconite) pellets fed to the taconite furnace(s) (metric tons). Iron = Annual mass of molten iron charged to the basic oxygen furnace(s) plus annual mass of direct reduced iron charged to the EAF(s) (metric tons). Scrap = Annual mass of ferrous scrap charged to the basic oxygen furnace(s) and EAF(s) (metric tons). Flux = Annual mass of flux materials charged to the basic oxygen furnace(s) and EAF(s) (metric tons). Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the basic oxygen furnace(s), EAF(s), and direct reduction furnace(s) (metric tons). Coal = Annual mass of coal charged to the coke oven battery(s) (metric tons). Feed = Annual mass of sinter feed material charged to the sinter process(es) (metric tons). Electrode = Annual mass of carbon electrode consumed in the EAF(s) (metric tons). Steel in = Annual mass of molten steel charged to the decarburization vessels (metric tons). Ore = Annual mass of iron ore or iron ore pellets fed to the direct reduction furnace(s) (metric tons). Other = Annual mass of other materials charged to the direction reduction furnace(s) (metric tons). (iii) The annual mass (metric tons) of all solid and liquid products and byproducts (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-11 of this section. Where: Products = Annual mass of all solid and liquid products and by-products (from all process units) specified in Equations Q-1 through Q-7 of § 98.173 (metric tons). n = Number of process units, all types. P = Annual mass of fired pellets produced by the taconite furnace (metric tons). R = Annual mass of air pollution control residue from all process units (metric tons). Steel out = Annual mass of steel produced by the basic oxygen furnace(s), EAF(s) and decarburization vessel(s) (metric tons). Slag = Annual mass of slag produced by the basic oxygen furnace(s) and EAF(s) (metric tons). Coke = Annual mass of coke produced by the non-recovery coke batteries (metric tons). Sinter = Annual mass of sinter produced from the sinter process(es) (metric tons). Iron = Annual mass of iron produced from the direct reduction furnace (metric tons). NM = Annual mass of non-metallic materials produced by the direct reduction furnace (metric tons). Where: Products = Annual mass of all solid and liquid products and by-products (from all process units) specified in Equations Q-1 through Q-7 of § 98.173 (metric tons). n = Number of process units, all types. P = Annual mass of fired pellets produced by the taconite furnace (metric tons). R = Annual mass of air pollution control residue from all process units (metric tons). Steel out = Annual mass of steel produced by the basic oxygen furnace(s), EAF(s) and decarburization vessel(s) (metric tons). Slag = Annual mass of slag produced by the basic oxygen furnace(s) and EAF(s) (metric tons). Coke = Annual mass of coke produced by the non-recovery coke batteries (metric tons). Sinter = Annual mass of sinter produced from the sinter process(es) (metric tons). Iron = Annual mass of iron produced from the direct reduction furnace (metric tons). NM = Annual mass of non-metallic materials produced by the direct reduction furnace (metric tons). (iv) The weighted average carbon content of all gaseous, liquid, and solid fuels (combined) included in Equation Q-9 of this section, calculated as specified in Equation Q-12 of this section. Where: CF avg = Weighted average carbon content of all gaseous, liquid, and solid fuels included in Equation Q-9 of this section (weight fraction). n = Number of gaseous, liquid, and solid fuel inputs to each process unit as used in Equation Q-9 of this section. C gf,i = Average carbon content of the gaseous fuel used in each process, from the fuel analysis results (kg C per kg of fuel). C lf,i = Carbon content of the liquid fuel used in each process, from the fuel analysis results (kg C per gallon of fuel. C sf = Carbon content of the solid fuel used in each process, from the fuel analysis (expressed as a decimal fraction, e.g., 95% = 0.95). Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process units (metric tons), as calculated in Equation Q-9. Where: CF avg = Weighted average carbon content of all gaseous, liquid, and solid fuels included in Equation Q-9 of this section (weight fraction). n = Number of gaseous, liquid, and solid fuel inputs to each process unit as used in Equation Q-9 of this section. C gf,i = Average carbon content of the gaseous fuel used in each process, from the fuel analysis results (kg C per kg of fuel). C lf,i = Carbon content of the liquid fuel used in each process, from the fuel analysis results (kg C per gallon of fuel. C sf = Carbon content of the solid fuel used in each process, from the fuel analysis (expressed as a decimal fraction, e.g., 95% = 0.95). Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process units (metric tons), as calculated in Equation Q-9. (v) The weighted average carbon content of all non-fuel inputs to all process units (combined) included in Equation Q-10 of this section, calculated as specified in Equation Q-13 of this section. Where: CI avg = Weighted average carbon content of all non-fuel inputs to all process units included in Equation Q-10 of this section (weight fraction). n = Number of non-fuel inputs to all process units as used in Equation Q-10. NFI i = Annual mass of each non-fuel input used in Equation Q-10 (metric tons). C NFIi = Average carbon content of each non-fuel input used in Equation Q-10 (expressed as a decimal fraction). NFI = Total of all non-fuel inputs to all process units (metric tons). Where: CI avg = Weighted average carbon content of all non-fuel inputs to all process units included in Equation Q-10 of this section (weight fraction). n = Number of non-fuel inputs to all process units as used in Equation Q-10. NFI i = Annual mass of each non-fuel input used in Equation Q-10 (metric tons). C NFIi = Average carbon content of each non-fuel input used in Equation Q-10 (expressed as a decimal fraction). NFI = Total of all non-fuel inputs to all process units (metric tons). (vi) The weighted average carbon content of all solid and liquid products and byproducts from all process units (combined) included in Equation Q-11 of this section, calculated as specified in Equation Q-14 of this section. Where: CP avg = Weighted average carbon content of all solid and liquid products and byproducts from all process units (weight fraction). n = Number of products and byproducts from each process unit as used in Equation Q-11 of this section. Product i = Annual mass of each product or byproduct used in Equation Q-11 (metric tons). C p,i = Average carbon content of each product or byproduct used in Equation Q-11 (expressed as a decimal fraction). Products = Mass of all products and byproducts from all process units, calculated in Equation Q-11 (metric tons). Where: CP avg = Weighted average carbon content of all solid and liquid products and byproducts from all process units (weight fraction). n = Number of products and byproducts from each process unit as used in Equation Q-11 of this section. Product i = Annual mass of each product or byproduct used in Equation Q-11 (metric tons). C p,i = Average carbon content of each product or byproduct used in Equation Q-11 (expressed as a decimal fraction). Products = Mass of all products and byproducts from all process units, calculated in Equation Q-11 (metric tons). (f) If you used the site-specific emission factor method in § 98.173(b)(2) to determine CO 2 emissions, you must report the following information for each process: (1) The measured average hourly CO 2 emission rate during the test (in metric tons per hour). (2)-(4) [Reserved] (g) For each unit, the type of unit, the annual production capacity, and annual operating hours. (h) For flares burning coke oven gas or blast furnace gas, the information specified in § 98.256(e) of subpart Y (Petroleum Refineries) of this part." 40:40:23.0.1.1.2.17.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.177 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013; 79 FR 63788, Oct. 24, 2014]","In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (f) of this section, as applicable. Facilities that use CEMS to measure emissions must also retain records of the verification data required for the Tier 4 Calculating Methodology in § 98.36(e). (a) Records of all analyses and calculations conducted, including all information reported as required under § 98.176. (b) When the carbon mass balance method is used to estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass, except that no determination of the mass of steel output from decarburization vessels is required. (c) Production capacity (in metric tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel. (d) Annual operating hours for each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, electric arc furnace, decarburization vessel, and direct reduction furnace. (e) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and bulk density). You also must document the procedures used to ensure the accuracy of the measurements of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage 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. (f) Verification software records. 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 (f)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (f)(1) through (9) of this section. (1) The data in paragraphs (f)(1)(i) through (xxv) of this section for each applicable taconite indurating furnace for which the carbon mass balance method of reporting is used. (i) Annual mass of each solid fuel (metric tons) (Equation Q-1 of § 98.173). (ii) Carbon content of each solid fuel, from the fuel analysis (expressed as a decimal fraction) (Equation Q-1). (iii) Annual volume of each gaseous fuel (scf) (Equation Q-1). (iv) Average carbon content of each gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-1). (v) Molecular weight of each gaseous fuel (kg/kg-mole) (Equation Q-1). (vi) Annual volume of each liquid fuel (gallons) (Equation Q-1). (vii) Carbon content of each liquid fuel, from the fuel analysis results (kg C per gallon of fuel) (Equation Q-1). (viii) Annual mass of the greenball (taconite) pellets fed to the furnace (metric tons) (Equation Q-1). (ix) Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1). (x) Annual mass of fired pellets produced by the furnace (metric tons) (Equation Q-1). (xi) Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1). (xii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-1). (xiii) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1). (xiv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-1). (xv) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1). (xvi) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-1). (xvii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-1). (xviii) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-1). (xix) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1). (xx) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-1). (xxi) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1). (xxii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-1). (xxiii) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1). (xxiv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-1). (xxv) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1). (2) The data in paragraphs (f)(2)(i) through (xxvi) of this section for each applicable basic oxygen process furnace for which the carbon mass balance method of reporting is used. (i) Annual mass of molten iron charged to the furnace (metric tons) (Equation Q-2 of § 98.173). (ii) Carbon content of the molten iron charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-2). (iv) Carbon content of the ferrous scrap charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (v) Annual mass of the flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (Equation Q-2). (vi) Carbon content of the flux materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (vii) Annual mass of the carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-2). (viii) Carbon content of the carbonaceous materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (ix) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-2). (x) Carbon content of the steel produced by the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (xi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-2). (xii) Carbon content of the slag produced by the furnace, from the carbon analysis (expressed as a decimal fraction) (Equation Q-2). (xiii) Annual mass of air pollution control residue collected for the furnace (metric tons) (Equation Q-2). (xiv) Carbon content of the air pollution control residue collected for the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2). (xv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-2). (xvi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2). (xvii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-2). (xviii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-2). (xix) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-2). (xx) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2). (xxi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-2). (xxii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2). (xxiii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-2). (xxiv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2). (xxv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-2). (xxvi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2). (3) The data in paragraphs (f)(3)(i) through (xviii) of this section for each applicable non-recovery coke oven battery for which the carbon mass balance method of reporting is used. (i) Annual mass of coal charged to the battery (metric tons) (Equation Q-3 of § 98.173). (ii) Carbon content of the coal, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3). (iii) Annual mass of coke produced by the battery (metric tons) (Equation Q-3). (iv) Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3). (v) Annual mass of air pollution control residue collected (metric tons) (Equation Q-3). (vi) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3). (vii) Annual mass of each other solid input containing carbon fed to each battery (metric tons) (Equation Q-3). (viii) Carbon content of each other solid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3). (ix) Annual mass of each other solid output containing carbon produced by each battery (metric tons) (Equation Q-3). (x) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-3). (xi) Annual mass of each other gaseous input containing carbon fed to each battery (metric tons) (Equation Q-3). (xii) Carbon content of each other gaseous input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3). (xiii) Annual mass of each other gaseous output containing carbon produced by each battery (metric tons) (Equation Q-3). (xiv) Carbon content of each other gaseous output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3). (xv) Annual mass of each other liquid input containing carbon fed to each battery (metric tons) (Equation Q-3). (xvi) Carbon content of each other liquid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3). (xvii) Annual mass of each other liquid output containing carbon produced by each battery (metric tons) (Equation Q-3). (xviii) Carbon content of each other liquid output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3). (4) The data in paragraphs (f)(4)(i) through (xxi) of this section for each applicable sinter process for which the carbon mass balance method of reporting is used. (i) Annual volume of the gaseous fuel (scf) (Equation Q-4 of § 98.173). (ii) Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-4). (iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-4). (iv) Annual mass of sinter feed material (metric tons) (Equation Q-4). (v) Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4). (vi) Annual mass of sinter produced (metric tons) (Equation Q-4). (vii) Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4). (viii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-4). (ix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4). (x) Annual mass of each other solid input containing carbon fed to each sinter process (metric tons) (Equation Q-4). (xi) Carbon content of each other solid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4). (xii) Annual mass of each other solid output containing carbon produced by each sinter process (metric tons) (Equation Q-4). (xiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-4). (xiv) Annual mass of each other gaseous input containing carbon fed to each sinter process (metric tons) (Equation Q-4). (xv) Carbon content of each other gaseous input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4). (xvi) Annual mass of each other gaseous output containing carbon produced by each sinter process (metric tons) (Equation Q-4). (xvii) Carbon content of each other gaseous output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4). (xviii) Annual mass of each other liquid input containing carbon fed to each sinter process (metric tons) (Equation Q-4). (xix) Carbon content of each other liquid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4). (xx) Annual mass of each other liquid output containing carbon produced by each sinter process (metric tons) (Equation Q-4). (xxi) Carbon content of each other liquid output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4). (5) The data in paragraphs (f)(5)(i) through (xxxi) of this section for each applicable electric arc furnace for which the carbon mass balance method of reporting is used. (i) Annual mass of direct reduced iron (if any) charged to the furnace (metric tons) (Equation Q-5 of § 98.173). (ii) Carbon content of the direct reduced iron, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5) (iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-5). (iv) Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (v) Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (EquationQ-5). (vi) Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (vii) Annual mass of carbon electrode consumed (metric tons) (Equation Q-5). (viii) Carbon content of the carbon electrode, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (ix) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-5). (x) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (xi) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-5). (xii) Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (xiii) Annual volume of the gaseous fuel (scf at 60F and 1 atm) (Equation Q-5). (xiv) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-5). (xv) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-5). (xvi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-5). (xvii) Carbon content of the slag, from the carbon analysis (expressed as a decimal fraction) (Equation Q-5). (xviii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-5). (xix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5). (xx) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-5). (xxi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5). (xxii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-5). (xxiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-5). (xxiv) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-5). (xxv) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5). (xxvi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-5). (xxvii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5). (xxviii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-5). (xxix) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5). (xxx) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-5). (xxxi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5). (6) The data in paragraphs (f)(6)(i) through (xvii) of this section for each applicable decarburization vessel for which the carbon mass balance method of reporting is used. (i) Annual mass of molten steel charged to the vessel (metric tons) (Equation Q-6 of § 98.173). (ii) Carbon content of the molten steel before decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6). (iii) Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6). (iv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-6). (v) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6). (vi) Annual mass of each other solid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6). (vii) Carbon content of each other solid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6). (viii) Annual mass of each other solid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6). (ix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-6). (x) Annual mass of each other gaseous input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6). (xi) Carbon content of each other gaseous input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6). (xii) Annual mass of each other gaseous output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6). (xiii) Carbon content of each other gaseous output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6). (xiv) Annual mass of each other liquid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6). (xv) Carbon content of each other liquid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6). (xvi) Annual mass of each other liquid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6). (xvii) Carbon content of each other liquid output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6). (7) The data in paragraphs (f)(7)(i) through (xxvii) of this section for each applicable direct reduction furnace for which the carbon mass balance method of reporting is used. (i) Annual volume of the gaseous fuel (scf at 68F and 1 atm) (Equation Q-7 of § 98.173). (ii) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-7). (iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-7). (iv) Annual mass of iron ore or iron pellets fed to the furnace (metric tons) (Equation Q-7). (v) Carbon content of the iron ore or iron pellets, from the carbon analysis (expressed as a decimal fraction) (Equation Q-7). (vi) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-7). (vii) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7). (viii) Annual mass of each other material charged to the furnace (metric tons) (Equation Q-7). (ix) Average carbon content of each other material charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7). (x) Annual mass of iron produced (metric tons) (Equation Q-7). (xi) Carbon content of the iron produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7). (xii) Annual mass of non-metallic materials produced by the furnace (metric tons) (Equation Q-7). (xiii) Carbon content of the non-metallic materials produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7). (xiv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-7). (xv) Carbon content of the air pollution control residue collected, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7). (xvi) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-7). (xvii) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7). (xviii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-7). (xix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-7). (xx) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-7). (xxi) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7). (xxii) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-7). (xxiii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7). (xxiv) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-7). (xxv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7). (xxvi) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-7). (xxvii) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7). (8) The data in paragraphs (f)(8)(i) and (ii) of this section for each process unit for which the site-specific emission factor method was used. (i) Average hourly feed or production rate, as applicable, during the test (metric tons/hour) (as used in § 98.173(b)(2)(iii)). (ii) Annual total feed or production, as applicable (metric tons) (as used in § 98.173(b)(2)(iv)). (9) Total coal charged to the coke ovens for each process (metric tons/year)(as used in § 98.173(c))." 40:40:23.0.1.1.2.17.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,Q,Subpart Q—Iron and Steel Production,,§ 98.178 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.18.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.180 Definition of the source category.,EPA,,,,"The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques. A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to, lead-acid batteries) are recycled by smelting into elemental lead or lead alloys." 40:40:23.0.1.1.2.18.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.181 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). 40:40:23.0.1.1.2.18.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.182 GHGs to report.,EPA,,,,"You must report: (a) Process CO 2 emissions from each smelting furnace used for lead production. (b) CO 2 combustion emissions from each smelting furnace used for lead production. (c) CH 4 and N 2 O combustion emissions from each smelting furnace used for lead production. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (d) CO 2 , CH 4 , and N 2 O emissions from each stationary combustion unit other than smelting furnaces used for lead production. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C." 40:40:23.0.1.1.2.18.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.183 Calculating GHG emissions.,EPA,,,,"You must calculate and report the annual process CO 2 emissions from each smelting furnace using the procedure in paragraphs (a) and (b) of this section. (a) For each smelting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 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 (General Stationary Fuel Combustion Sources). (b) For each smelting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 emissions from the smelting furnace by using the procedure in either paragraph (b)(1) or (b)(2) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions by operating and maintaining a CEMS to measure CO 2 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 (General Stationary Fuel Combustion Sources). (2) Calculate and report process and combustion CO 2 emissions separately using the procedures specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section. (i) For each smelting furnace, determine the annual mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnace and estimate annual process CO 2 emissions using Equation R-1 of this section. Carbon-containing 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 of this section. Where: E CO2 = Annual process CO 2 emissions from an individual smelting furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. Ore = Annual mass of lead ore charged to the smelting furnace (tons). C Ore = Carbon content of the lead ore, from the carbon analysis results (percent by weight, expressed as a decimal fraction). Scrap = Annual mass of lead scrap charged to the smelting furnace (tons). C Scrap = Carbon content of the lead scrap, from the carbon analysis (percent by weight, expressed as a decimal fraction). Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged to the smelting furnace (tons). C Flux = Carbon content of the flux materials, from the carbon analysis (percent by weight, expressed as a decimal fraction). Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the smelting furnace (tons). C Carbon = Carbon content of the carbonaceous materials, from the carbon analysis (percent by weight, expressed as a decimal fraction). Other = Annual mass of any other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons). C Other = Carbon content of the other material from the carbon analysis results (percent by weight, expressed as a decimal fraction). Where: E CO2 = Annual process CO 2 emissions from an individual smelting furnace (metric tons). 44/12 = Ratio of molecular weights, CO 2 to carbon. 2000/2205 = Conversion factor to convert tons to metric tons. Ore = Annual mass of lead ore charged to the smelting furnace (tons). C Ore = Carbon content of the lead ore, from the carbon analysis results (percent by weight, expressed as a decimal fraction). Scrap = Annual mass of lead scrap charged to the smelting furnace (tons). C Scrap = Carbon content of the lead scrap, from the carbon analysis (percent by weight, expressed as a decimal fraction). Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged to the smelting furnace (tons). C Flux = Carbon content of the flux materials, from the carbon analysis (percent by weight, expressed as a decimal fraction). Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the smelting furnace (tons). C Carbon = Carbon content of the carbonaceous materials, from the carbon analysis (percent by weight, expressed as a decimal fraction). Other = Annual mass of any other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons). C Other = Carbon content of the other material from the carbon analysis results (percent by weight, expressed as a decimal fraction). (ii) Determine the combined annual process CO 2 emissions from the smelting furnaces at your facility using Equation R-2 of this section. Where: CO 2 = Annual process CO 2 emissions from smelting furnaces at facility used for lead production (metric tons). E CO2 k = Annual process CO 2 emissions from smelting furnace k calculated using Equation R-1 of this section (metric tons/year). k = Total number of smelting furnaces at facility used for lead production. Where: CO 2 = Annual process CO 2 emissions from smelting furnaces at facility used for lead production (metric tons). E CO2 k = Annual process CO 2 emissions from smelting furnace k calculated using Equation R-1 of this section (metric tons/year). k = Total number of smelting furnaces at facility used for lead production. (iii) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 emissions from the smelting furnaces according to the applicable requirements in subpart C." 40:40:23.0.1.1.2.18.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.184 Monitoring and QA/QC requirements.,EPA,,,,"If you determine process CO 2 emissions using the carbon mass balance procedure in § 98.183(b)(2)(i) and (b)(2)(ii), 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 CO 2 emissions using Equation R-1 of this subpart 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 or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(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 each year. The carbon content of the material must be analyzed at least annually using the methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. (i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7) for analysis of metal ore and alloy product. (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes. (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials such as limestone or dolomite." 40:40:23.0.1.1.2.18.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.185 Procedures for estimating missing data.,EPA,,,,"A complete record of all measured parameters used in the GHG emissions calculations in § 98.183 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall 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) For each missing data for the carbon content for the smelting furnaces at your facility that estimate annual process CO 2 emissions using the carbon mass balance procedure in § 98.183(b)(2)(i) and (ii), 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.184(b) if data are missing. (b) For missing records of the monthly mass of carbon-containing materials, the substitute data value must be based the best available estimate of the mass of the material from all available process data or data used for accounting purposes (such as purchase records)." 40:40:23.0.1.1.2.18.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.186 Data reporting procedures.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]","In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable. (a) If a CEMS is used to measure CO 2 emissions according to the requirements in § 98.183(a) or (b)(1), then you must report under this subpart the relevant information required by § 98.36 and the information specified in paragraphs (a)(1) through (a)(4) of this section. (1) Identification number of each smelting furnace. (2) Annual lead product production capacity (tons). (3) Annual production for each lead product (tons). (4) Total number of smelting furnaces at facility used for lead production. (b) If a CEMS is not used to measure CO 2 emissions, and you measure CO 2 emissions according to the requirements in § 98.183(b)(2)(i) and (b)(2)(ii), then you must report the information specified in paragraphs (b)(1) through (b)(9) of this section. (1) Identification number of each smelting furnace. (2) Annual process CO 2 emissions (in metric tons) from each smelting furnace as determined by Equation R-1 of this subpart. (3) Annual lead product production capacity for the facility and each smelting furnace(tons). (4) Annual production for each lead product (tons). (5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of this section. (6)-(7) [Reserved] (8) List the method used for the determination of carbon content for each material used for the calculation of annual process CO 2 emissions using Equation R-1 of § 98.183 for each smelting furnace (e.g., supplier provided information, analyses of representative samples you collected). (9) If you use the missing data procedures in § 98.185(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used." 40:40:23.0.1.1.2.18.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.187 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]","In addition to the records required by § 98.3(g), you must retain the records of the information specified in paragraphs (a) through (d) of this section, as applicable to the smelting furnaces at your facility. (a) If a CEMS is used to measure combined process and combustion CO 2 emissions according to the requirements in § 98.183(a) or (b)(1), then you must retain the records required for the Tier 4 Calculation Methodology in § 98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this section. (1) Monthly smelting furnace production quantity for each lead product (tons). (2) Number of smelting furnace operating hours each month. (3) Number of smelting furnace operating hours in calendar year. (b) If the carbon mass balance procedure is used to determine process CO 2 emissions according to the requirements in § 98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart the records specified in paragraphs (b)(1) through (b)(5) of this section. (1) Monthly smelting furnace production quantity for each lead product (tons). (2) Number of smelting furnace operating hours each month. (3) Number of smelting furnace operating hours in calendar year. (4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO 2 emissions using Equation R-1 of this subpart (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 CO 2 emissions using Equation R-1 of this subpart. (c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace, including documentation of any materials excluded from Equation R-1 of this subpart 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 an smelting furnace 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) Verification software records. 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 (10) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (10) of this section. (1) Annual mass of lead ore charged to each smelting furnace (tons) (Equation R-1 of § 98.183). (2) Carbon content of the lead ore per furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation R-1). (3) Annual mass of lead scrap charged to each smelting furnace (tons) (Equation R-1). (4) Carbon content of the lead scrap per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1). (5) Annual mass of flux materials (e.g., limestone, dolomite) charged to each smelting furnace (tons) (Equation R-1). (6) Carbon content of the flux materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1). (7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each smelting furnace (tons) (Equation R-1). (8) Carbon content of the carbonaceous materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1). (9) Annual mass of each other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons) (Equation R-1). (10) Carbon content of each other material, from the carbon analysis results per furnace (percent by weight, expressed as a decimal fraction) (Equation R-1)." 40:40:23.0.1.1.2.18.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,R,Subpart R—Lead Production,,§ 98.188 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.19.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.190 Definition of the source category.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013]","(a) Lime manufacturing plants (LMPs) engage in the manufacture of a lime product by calcination of limestone, dolomite, shells or other calcareous substances as defined in 40 CFR 63.7081(a)(1). (b) This source category includes all LMPs unless the LMP is located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only processes sludge containing calcium carbonate from water softening processes. The lime manufacturing source category consists of marketed and non-marketed lime manufacturing facilities. (c) Lime kilns at pulp and paper manufacturing facilities must report emissions under subpart AA of this part (Pulp and Paper Manufacturing)." 40:40:23.0.1.1.2.19.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.191 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility is a lime manufacturing plant as defined in § 98.190 and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). 40:40:23.0.1.1.2.19.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.192 GHGs to report.,EPA,,,,"You must report: (a) CO 2 process emissions from lime kilns. (b) CO 2 emissions from fuel combustion at lime kilns. (c) N 2 O and CH 4 emissions from fuel combustion at each lime kiln. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). (d) CO 2 , N 2 O, and CH 4 emissions from each stationary fuel combustion unit other than lime kilns. You must report these emissions under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). (e) CO 2 collected and transferred off site under 40 CFR part 98, following the requirements of subpart PP of this part (Suppliers of Carbon Dioxide (CO 2 ))." 40:40:23.0.1.1.2.19.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.193 Calculating GHG emissions.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013; 81 FR 89258, Dec. 9, 2016; 89 FR 31928, Apr. 25, 2024]","You must calculate and report the annual process CO 2 emissions from all lime kilns combined using the procedure in paragraphs (a) and (b) of this section. (a) If all lime kilns meet the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO 2 emissions from all lime kilns by operating and maintaining a CEMS to measure CO 2 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 (General Stationary Fuel Combustion Sources). (b) If CEMS are not required to be used to determine CO 2 emissions from all lime kilns under paragraph (a) of this section, then you must calculate and report the process and combustion CO 2 emissions from the lime kilns by using the procedures in either paragraph (b)(1) or (b)(2) of this section. (1) Calculate and report under this subpart the combined process and combustion CO 2 emissions from all lime kilns by operating and maintaining a CEMS to measure CO 2 emissions from all lime kilns 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 (General Stationary Fuel Combustion Sources). (2) Calculate and report process and combustion CO 2 emissions from all lime kilns separately using the procedures specified in paragraphs (b)(2)(i) through (viii) of this section. (i) You must calculate a monthly emission factor for each type of lime produced using Equation S-1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each lime product type that is produced: Where: EF LIME,i,n = Emission factor for lime type i, for month n (metric tons CO 2 /ton lime). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate [see Table S-1 of this subpart] (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO i,n = Calcium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons CaO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. Where: EF LIME,i,n = Emission factor for lime type i, for month n (metric tons CO 2 /ton lime). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate [see Table S-1 of this subpart] (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO i,n = Calcium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons CaO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for month n, determined according to § 98.194(c) (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. (ii) You must calculate a monthly emission factor for each type of calcined byproduct or waste sold (including lime kiln dust) using Equation S-2 of this section: Where: EF LKD,i,n = Emission factor for calcined lime byproduct/waste type i sold, for month n (metric tons CO 2 /ton lime byproduct). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart((metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO LKD,i,n = Calcium oxide content for calcined lime byproduct/waste type i sold, for month n (metric tons CaO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for calcined lime byproduct/waste type i sold, for month n (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. Where: EF LKD,i,n = Emission factor for calcined lime byproduct/waste type i sold, for month n (metric tons CO 2 /ton lime byproduct). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart((metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO LKD,i,n = Calcium oxide content for calcined lime byproduct/waste type i sold, for month n (metric tons CaO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for calcined lime byproduct/waste type i sold, for month n (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for tons to metric tons. (iii) You must calculate the annual CO 2 emissions from each type of calcined byproduct or waste that is not sold (including lime kiln dust and scrubber sludge) using Equation S-3 of this section: Where: E waste,i = Annual CO 2 emissions for calcined lime byproduct or waste type i that is not sold (metric tons CO 2 ). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart) (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO waste,i = Calcium oxide content for calcined lime byproduct or waste type i that is not sold (metric tons CaO/metric ton lime). MgO waste,i = Magnesium oxide content for calcined lime byproduct or waste type i that is not sold (metric tons MgO/metric ton lime). M waste,i = Annual weight or mass of calcined byproducts or wastes for lime type i that is not sold (tons). 2000/2205 = Conversion factor for tons to metric tons. Where: E waste,i = Annual CO 2 emissions for calcined lime byproduct or waste type i that is not sold (metric tons CO 2 ). SR CaO = Stoichiometric ratio of CO 2 and CaO for calcium carbonate (see Table S-1 of this subpart) (metric tons CO 2 /metric tons CaO). SR MgO = Stoichiometric ratio of CO 2 and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons CO 2 /metric tons MgO). CaO waste,i = Calcium oxide content for calcined lime byproduct or waste type i that is not sold (metric tons CaO/metric ton lime). MgO waste,i = Magnesium oxide content for calcined lime byproduct or waste type i that is not sold (metric tons MgO/metric ton lime). M waste,i = Annual weight or mass of calcined byproducts or wastes for lime type i that is not sold (tons). 2000/2205 = Conversion factor for tons to metric tons. (iv) You must calculate annual CO 2 process emissions for all lime kilns using Equation S-4 of this section: Where: E CO2 = Annual CO 2 process emissions from lime production from all lime kilns (metric tons/year). EF LIME,i,n = Emission factor for lime type i produced, in calendar month n (metric tons CO 2 /ton lime) from Equation S-1 of this section. M LIME,i,n = Weight or mass of lime type i produced in calendar month n (tons). EF LKD,i,n = Emission factor of calcined byproducts or wastes sold for lime type i in calendar month n, (metric tons CO 2 /ton byproduct or waste) from Equation S-2 of this section. M LKD,i,n = Monthly weight or mass of calcined byproducts or waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons). E waste,i = Annual CO 2 emissions for calcined lime byproduct or waste type i that is not sold (metric tons CO 2 ) from Equation S-3 of this section. t = Number of lime types produced b = Number of calcined byproducts or wastes that are sold. z = Number of calcined byproducts or wastes that are not sold. Where: E CO2 = Annual CO 2 process emissions from lime production from all lime kilns (metric tons/year). EF LIME,i,n = Emission factor for lime type i produced, in calendar month n (metric tons CO 2 /ton lime) from Equation S-1 of this section. M LIME,i,n = Weight or mass of lime type i produced in calendar month n (tons). EF LKD,i,n = Emission factor of calcined byproducts or wastes sold for lime type i in calendar month n, (metric tons CO 2 /ton byproduct or waste) from Equation S-2 of this section. M LKD,i,n = Monthly weight or mass of calcined byproducts or waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons). E waste,i = Annual CO 2 emissions for calcined lime byproduct or waste type i that is not sold (metric tons CO 2 ) from Equation S-3 of this section. t = Number of lime types produced b = Number of calcined byproducts or wastes that are sold. z = Number of calcined byproducts or wastes that are not sold. (v) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 emissions from each lime kiln according to the applicable requirements in subpart C. (vi) You must calculate an annual average emission factor for each type of lime product produced using Equation S-5 of this section. Where: EF LIME,i,avg = Annual average emission factor for lime type i, (metric tons CO 2 /ton lime) EF LIME,i,n = Emission factor for lime type i, for calendar month n (metric tons CO 2 /ton lime) from Equation S-1 of this section. n = Number of calendar months with calculated EF LIME,i,n value used to calculate annual emission factor. Where: EF LIME,i,avg = Annual average emission factor for lime type i, (metric tons CO 2 /ton lime) EF LIME,i,n = Emission factor for lime type i, for calendar month n (metric tons CO 2 /ton lime) from Equation S-1 of this section. n = Number of calendar months with calculated EF LIME,i,n value used to calculate annual emission factor. (vii) You must calculate an annual average emission factor for each type of calcined byproduct/waste by lime type that is sold using Equation S-6 of this section. Where: EF LKD,i,avg = Annual average emission factor for calcined lime byproduct/waste type i sold (metric tons CO 2 /ton lime byproduct). EF LKD,i,n = Emission factor for calcined lime byproduct/waste type i sold, for calendar month n (metric tons CO 2 /ton lime byproduct) from Equation S-2 of this section. n = Number of calendar months with calculated EF LKD,i,n value used to calculate annual emission factor. Where: EF LKD,i,avg = Annual average emission factor for calcined lime byproduct/waste type i sold (metric tons CO 2 /ton lime byproduct). EF LKD,i,n = Emission factor for calcined lime byproduct/waste type i sold, for calendar month n (metric tons CO 2 /ton lime byproduct) from Equation S-2 of this section. n = Number of calendar months with calculated EF LKD,i,n value used to calculate annual emission factor. (viii) You must calculate an annual average result of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold using Equations S-7 through S-10 of this section. Where CaO i,avg = Annual average calcium oxide content for lime type i (metric tons CaO/metric ton lime). CaO i,n = Calcium oxide content for lime type i, for calendar month n, determined according to § 98.194(c) for Equation S-1 of this section (metric tons CaO/metric ton lime). n = Number of calendar months with calculated CaO ,i,n value used to calculate annual average calcium oxide content. Where CaO i,avg = Annual average calcium oxide content for lime type i (metric tons CaO/metric ton lime). CaO i,n = Calcium oxide content for lime type i, for calendar month n, determined according to § 98.194(c) for Equation S-1 of this section (metric tons CaO/metric ton lime). n = Number of calendar months with calculated CaO ,i,n value used to calculate annual average calcium oxide content. Where: MgO i,avg = Annual average magnesium oxide content for lime type i (metric tons MgO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for calendar month n, determined according to § 98.194(c) for Equation S-1 of this section (metric tons MgO/metric ton lime). n = Number of calendar months with calculated MgO ,i,n value used to calculate annual average magnesium oxide content. Where: MgO i,avg = Annual average magnesium oxide content for lime type i (metric tons MgO/metric ton lime). MgO i,n = Magnesium oxide content for lime type i, for calendar month n, determined according to § 98.194(c) for Equation S-1 of this section (metric tons MgO/metric ton lime). n = Number of calendar months with calculated MgO ,i,n value used to calculate annual average magnesium oxide content. Where: CaO LKD,i,avg = Annual average calcium oxide content for calcined lime byproduct/waste type i sold (metric tons CaO/metric ton lime). CaO LKD,i,n = Calcium oxide content for calcined lime byproduct/waste type i sold, for calendar month n, determined according to § 98.194(c) for Equation S-2 of this section (metric tons CaO/metric ton lime). n = Number of calendar months with calculated CaO LKD,i,n value used to calculate annual average calcium oxide content. Where: CaO LKD,i,avg = Annual average calcium oxide content for calcined lime byproduct/waste type i sold (metric tons CaO/metric ton lime). CaO LKD,i,n = Calcium oxide content for calcined lime byproduct/waste type i sold, for calendar month n, determined according to § 98.194(c) for Equation S-2 of this section (metric tons CaO/metric ton lime). n = Number of calendar months with calculated CaO LKD,i,n value used to calculate annual average calcium oxide content. Where: MgO LKD,i,avg = Annual average magnesium oxide content for calcined lime byproduct/waste type i sold (metric tons MgO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for calcined lime byproduct/waste type i sold, for calendar month n, determined according to § 98.194(c) for Equation S-2 of this section (metric tons MgO/metric ton lime). n = Number of calendar months with calculated MgO LKD,i,n value used to calculate annual average magnesium oxide content. Where: MgO LKD,i,avg = Annual average magnesium oxide content for calcined lime byproduct/waste type i sold (metric tons MgO/metric ton lime). MgO LKD,i,n = Magnesium oxide content for calcined lime byproduct/waste type i sold, for calendar month n, determined according to § 98.194(c) for Equation S-2 of this section (metric tons MgO/metric ton lime). n = Number of calendar months with calculated MgO LKD,i,n value used to calculate annual average magnesium oxide content." 40:40:23.0.1.1.2.19.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.194 Monitoring and QA/QC requirements.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013]","(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold. (b) You must determine the annual quantity of each calcined byproduct or waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct or waste generation rate. (c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct or waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct or waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct or waste that is not sold on an annual basis. (1) ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference— see § 98.7). (2) The National Lime Association's CO 2 Emissions Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision-National Lime Association (incorporated by reference—see § 98.7). (d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product that is produced and that is collected during the same month as the production data in monthly calculations. (e) You must follow the quality assurance/quality control procedures (including documentation) in National Lime Association's CO 2 Emissions Calculation Protocol for the Lime Industry English Units Version, February 5, 2008 Revision—National Lime Association (incorporated by reference— see § 98.7)." 40:40:23.0.1.1.2.19.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.195 Procedures for estimating missing data.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 78 FR 71959, Nov. 29, 2013]","For the procedure in § 98.193(b)(1), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., oxide content, quantity of lime products, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct or waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes. (b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in § 98.194 (c)(1) or (c)(2)." 40:40:23.0.1.1.2.19.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.196 Data reporting requirements.,EPA,,,"[75 FR 66465, Oct. 28, 2010, as amended at 78 FR 71959, Nov. 29, 2013; 79 FR 63792, Oct. 24, 2014; 81 FR 89259, Dec. 9, 2016; 89 FR 31928, Apr. 25, 2024]","In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable. (a) If a CEMS is used to measure CO 2 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. (1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold. (2) Method used to determine the quantity of calcined lime byproduct or waste sold. (3) Beginning and end of year inventories for each lime product that is produced, by type. (4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type. (5) Annual amount of calcined lime byproduct or waste sold, by type (tons). (6) Annual amount of lime product sold, by type (tons). (7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons). (8) Annual amount of lime product not sold, by type (tons). (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 CO 2 emissions, then you must report the information listed in paragraphs (b)(1) through (23) of this section. (1) Annual CO 2 process emissions from all lime kilns combined (metric tons). (2)-(3) [Reserved] (4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type. (5)-(6) [Reserved] (7) Method used to determine the quantity of lime produced and/or lime sold. (8) [Reserved] (9) Method used to determine the quantity of calcined lime byproduct or waste sold. (10)-(12) [Reserved] (13) Beginning and end of year inventories for each lime product that is produced. (14) Beginning and end of year inventories for calcined lime byproducts or wastes sold. (15) Annual lime production capacity (tons) per facility. (16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months). (17) Indicate whether CO 2 was captured and used on-site ( e.g., for use in a purification process, the manufacture of another product). If CO 2 was captured and used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section. (i) The annual amount of CO 2 captured for use in all on-site processes. (ii) The method used to determine the amount of CO 2 captured. (18) Annual quantity (tons) of lime product sold, by type. (19) Annual average emission factors for each lime product type produced. (20) Annual average emission factors for each calcined byproduct/waste by lime type that is sold. (21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold. (22) Annual average results of chemical composition analysis of all lime byproducts or wastes not sold. (23) Annual quantity (tons) of all lime byproducts or wastes not sold." 40:40:23.0.1.1.2.19.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.197 Records that must be retained.,EPA,,,"[74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]","In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section. (a) Annual operating hours in calendar year. (b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted. (c) Verification software records. 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 (c)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (9) of this section. (1) Monthly calcium oxide content for each lime type, determined according to § 98.194(c) (metric tons CaO/metric ton lime) (Equation S-1 of § 98.193). (2) Monthly magnesium oxide content for each lime type, determined according to § 98.194(c) (metric tons MgO/metric ton lime) (Equation S-1). (3) Monthly calcium oxide content for each calcined lime byproduct or waste type sold (metric tons CaO/metric ton lime) (Equation S-2 of § 98.193). (4) Monthly magnesium oxide content for each calcined lime byproduct or waste type sold (metric tons MgO/metric ton lime) (Equation S-2). (5) Calcium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons CaO/metric ton lime) (Equation S-3 of § 98.193). (6) Magnesium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons MgO/metric ton lime) (Equation S-3). (7) Annual weight or mass of calcined byproducts or wastes for lime type that is not sold (tons) (Equation S-3). (8) Monthly weight or mass of each lime type produced (tons) (Equation S-4 of § 98.193). (9) Monthly weight or mass of each calcined byproducts or wastes sold (tons) (Equation S-4)." 40:40:23.0.1.1.2.19.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,S,Subpart S—Lime Manufacturing,,§ 98.198 Definitions.,EPA,,,,All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. 40:40:23.0.1.1.2.20.1.1,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.200 Definition of source category.,EPA,,,,"The magnesium production and processing source category consists of the following processes: (a) Any process in which magnesium metal is produced through smelting (including electrolytic smelting), refining, or remelting operations. (b) Any process in which molten magnesium is used in alloying, casting, drawing, extruding, forming, or rolling operations." 40:40:23.0.1.1.2.20.1.2,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.201 Reporting threshold.,EPA,,,,You must report GHG emissions under this subpart if your facility contains a magnesium production process and the facility meets the requirements of either § 98.2(a)(1) or (2). 40:40:23.0.1.1.2.20.1.3,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.202 GHGs to report.,EPA,,,,"(a) You must report emissions of the following gases in metric tons per year resulting from their use as cover gases or carrier gases in magnesium production or processing: (1) Sulfur hexafluoride (SF 6 ). (2) HFC-134a. (3) The fluorinated ketone, FK 5-1-12. (4) Carbon dioxide (CO 2 ). (5) Any other GHGs (as defined in § 98.6). (b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO 2 , N 2 O, and CH 4 emissions from each combustion unit by following the requirements of subpart C." 40:40:23.0.1.1.2.20.1.4,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.203 Calculating GHG emissions.,EPA,,,,"(a) Calculate the mass of each GHG emitted from magnesium production or processing over the calendar year using either Equation T-1 or Equation T-2 of this section, as appropriate. Both of these equations equate emissions of cover gases or carrier gases to consumption of cover gases or carrier gases. (1) To estimate emissions of cover gases or carrier gases by monitoring changes in container masses and inventories, emissions of each cover gas or carrier gas shall be estimated using Equation T-1 of this section: Where: E X = Emissions of each cover gas or carrier gas, X, in metric tons over the reporting year. I B,x = Inventory of each cover gas or carrier gas stored in cylinders or other containers at the beginning of the year, including heels, in kg. I E,x = Inventory of each cover gas or carrier gas stored in cylinders or other containers at the end of the year, including heels, in kg. A X = Acquisitions of each cover gas or carrier gas during the year through purchases or other transactions, including heels in cylinders or other containers returned to the magnesium production or processing facility, in kg. D X = Disbursements of each cover gas or carrier gas to sources and locations outside the facility through sales or other transactions during the year, including heels in cylinders or other containers returned by the magnesium production or processing facility to the gas supplier, in kg. 0.001 = Conversion factor from kg to metric tons X = Each cover gas or carrier gas that is a GHG. Where: E X = Emissions of each cover gas or carrier gas, X, in metric tons over the reporting year. I B,x = Inventory of each cover gas or carrier gas stored in cylinders or other containers at the beginning of the year, including heels, in kg. I E,x = Inventory of each cover gas or carrier gas stored in cylinders or other containers at the end of the year, including heels, in kg. A X = Acquisitions of each cover gas or carrier gas during the year through purchases or other transactions, including heels in cylinders or other containers returned to the magnesium production or processing facility, in kg. D X = Disbursements of each cover gas or carrier gas to sources and locations outside the facility through sales or other transactions during the year, including heels in cylinders or other containers returned by the magnesium production or processing facility to the gas supplier, in kg. 0.001 = Conversion factor from kg to metric tons X = Each cover gas or carrier gas that is a GHG. (2) To estimate emissions of cover gases or carrier gases by monitoring changes in the masses of individual containers as their contents are used, emissions of each cover gas or carrier gas shall be estimated using Equation T-2 of this section: Where: E GHG = Emissions of each cover gas or carrier gas, X, over the reporting year (metric tons). Q p = The mass of the cover or carrier gas consumed (kg) over the container-use period p, from Equation T-3 of this section. n = The number of container-use periods in the year. 0.001 = Conversion factor from kg to metric tons. X = Each cover gas or carrier gas that is a GHG. Where: E GHG = Emissions of each cover gas or carrier gas, X, over the reporting year (metric tons). Q p = The mass of the cover or carrier gas consumed (kg) over the container-use period p, from Equation T-3 of this section. n = The number of container-use periods in the year. 0.001 = Conversion factor from kg to metric tons. X = Each cover gas or carrier gas that is a GHG. (b) For purposes of Equation T-2 of this section, the mass of the cover gas used over the period p for an individual container shall be estimated by using Equation T-3 of this section: Where: Q p = The mass of the cover or carrier gas consumed (kg) over the container-use period p ( e.g., one month). M B = The mass of the container's contents (kg) at the beginning of period p. M E = The mass of the container's contents (kg) at the end of period p. Where: Q p = The mass of the cover or carrier gas consumed (kg) over the container-use period p ( e.g., one month). M B = The mass of the container's contents (kg) at the beginning of period p. M E = The mass of the container's contents (kg) at the end of period p. (c) If a facility has mass flow controllers (MFC) and the capacity to track and record MFC measurements to estimate total gas usage, the mass of each cover or carrier gas monitored may be used as the mass of cover or carrier gas consumed (Q p ), in kg for period p in Equation T-2 of this section." 40:40:23.0.1.1.2.20.1.5,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.204 Monitoring and QA/QC requirements.,EPA,,,,"(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request 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 January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011. (b) Emissions (consumption) of cover gases and carrier gases may be estimated by monitoring the changes in container weights and inventories using Equation T-1 of this subpart, by monitoring the changes in individual container weights as the contents of each container are used using Equations T-2 and T-3 of this subpart, or by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system. Emissions must be estimated at least annually. (c) When estimating emissions by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system, you must use gas flow meters, or mass flow controllers, with an accuracy of 1 percent of full scale or better. (d) When estimating emissions using Equation T-1 of this subpart, you must ensure that all the quantities required by Equation T-1 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting 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 containers containing new gas or for the heels remaining in containers 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 or weights under this subpart. (e) When estimating emissions using Equations T-2 and T-3 of this subpart, you must monitor and record container identities and masses as follows: (1) Track the identities and masses of containers leaving and entering storage with check-out and check-in sheets and procedures. The masses of cylinders returning to storage shall be measured immediately before the cylinders are put back into storage. (2) Ensure that all the quantities required by Equations T-2 and T-3 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting 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 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 or weights under this subpart. (f) All flowmeters, scales, and load cells used to measure quantities that are to be reported under this subpart shall be calibrated using calibration procedures specified by the flowmeter, scale, or load cell manufacturer. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at the minimum frequency specified by the manufacturer." 40:40:23.0.1.1.2.20.1.6,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.205 Procedures for estimating missing data.,EPA,,,,"(a) A complete record of all measured parameters used in the GHG emission calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter will be used in the calculations as specified in paragraph (b) of this section. (b) Replace missing data on the emissions of cover or carrier gases by multiplying magnesium production during the missing data period by the average cover or carrier gas usage rate from the most recent period when operating conditions were similar to those for the period for which the data are missing. Calculate the usage rate for each cover or carrier gas using Equation T-4 of this section: Where: R GHG = The usage rate for a particular cover or carrier gas over the period of comparable operation (metric tons gas/metric ton Mg). C GHG = The consumption of that cover or carrier gas over the period of comparable operation (kg). Mg = The magnesium produced or fed into the process over the period of comparable operation (metric tons). 0.001 = Conversion factor from kg to metric tons. Where: R GHG = The usage rate for a particular cover or carrier gas over the period of comparable operation (metric tons gas/metric ton Mg). C GHG = The consumption of that cover or carrier gas over the period of comparable operation (kg). Mg = The magnesium produced or fed into the process over the period of comparable operation (metric tons). 0.001 = Conversion factor from kg to metric tons. (c) If the precise before and after weights are not available, it should be assumed that the container was emptied in the process ( i.e., quantity purchased should be used, less heel)." 40:40:23.0.1.1.2.20.1.7,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.206 Data reporting requirements.,EPA,,,,"In addition to the information required by § 98.3(c), each annual report must include the following information at the facility level: (a) Emissions of each cover or carrier gas in metric tons. (b) Types of production processes at the facility ( e.g., primary, secondary, die casting). (c) Amount of magnesium produced or processed in metric tons for each process type. This includes the output of primary and secondary magnesium production processes and the input to magnesium casting processes. (d) Cover and carrier gas flow rate ( e.g., standard cubic feet per minute) for each production unit and composition in percent by volume. (e) For any missing data, you must report the length of time the data were missing for each cover gas or carrier gas, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated. (f) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg). (g) If applicable, an explanation of any change greater than 30 percent in the facility's cover gas usage rate ( e.g., installation of new melt protection technology or leak discovered in the cover gas delivery system that resulted in increased emissions). (h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year." 40:40:23.0.1.1.2.20.1.8,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.207 Records that must be retained.,EPA,,,,"In addition to the records specified in § 98.3(g), you must retain the following information at the facility level: (a) Check-out and weigh-in sheets and procedures for gas cylinders. (b) Accuracy certifications and calibration records for scales including the method or manufacturer's specification used for calibration. (c) Residual gas amounts (heel) in cylinders sent back to suppliers. (d) Records, including invoices, for gas purchases, sales, and disbursements for all GHGs." 40:40:23.0.1.1.2.20.1.9,40,Protection of Environment,I,C,98,PART 98—MANDATORY GREENHOUSE GAS REPORTING,T,Subpart T—Magnesium Production,,§ 98.208 Definitions.,EPA,,,,"All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additionally, some sector-specific definitions are provided below: Carrier gas means the gas with which cover gas is mixed to transport and dilute the cover gas thus maximizing its efficient use. Carrier gases typically include CO 2 , N 2 , and/or dry air. Cover gas means SF 6 , HFC-134a, fluorinated ketone (FK 5-1-12) or other gas used to protect the surface of molten magnesium from rapid oxidation and burning in the presence of air. The molten magnesium may be the surface of a casting or ingot production operation or the surface of a crucible of molten magnesium that feeds a casting operation."