40 CFR Part 98 — Mandatory Greenhouse Gas Reporting

PART 98—MANDATORY GREENHOUSE GAS REPORTING Authority: 42 U.S.C. 7401-7671q. Source: 74 FR 56374, Oct. 30, 2009, unless otherwise noted. Editorial Note: At 90 FR 21227, May 19, 2025, as required by the Congressional Review Act and Public Law 119-2, the Environmental Protection Agency removed the amendments to §§ 98.3 and 98.4 made effective on Jan. 17, 2025, at 89 FR 91163, Nov. 18, 2024. As of May 19, 2025, §§ 98.3 and 98.4 reverted to the Jan. 16, 2025 version. Subpart A—General Provision § 98.1 Purpose and scope. (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 Operator Onshore petroleum and natural gas production owner or operator, Owner Operator Gathering and boosting system owner or operator, Owner Operator Onshore natural gas transmission pipeline owner or operator, [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] § 98.2 Who must report? (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. (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. (3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). (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 (4) A supplier that is 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 2 (1) Calculate the annual emissions of CO 2 4 2 (2) For each general stationary fuel combustion unit, calculate the annual CO 2 4 2 4 2 (3) For miscellaneous uses of carbonate, calculate the annual CO 2 (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 Where: CO 2 GHG i GWP i 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 (c) To calculate GHG emissions for comparison to the 25,000 metric ton CO 2 2 4 2 2 (d) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 2 2 (e) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 2 2 (f) To calculate GHG quantities for comparison to the 25,000 metric ton CO 2 2 2 2 (1) Calculate the mass in metric tons per year of CO 2 2 2 2 (2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO 2 (3) Sum the total annual metric tons of CO 2 2 (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 2 2 (2) If reported CO 2 2 2 (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 2 e.g., (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 2 (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 (3) Sum the total annual metric tons of CO 2 [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] § 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part? 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. (b) Schedule. (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. (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 4 2 (i) Annual emissions (excluding biogenic CO 2 2 2 (ii) Annual emissions of biogenic CO 2 (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 2 (C) CH 4 (D) N 2 (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 ( 2 ( 3 (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 4 2 (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 (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. (ii) Additional NAICS code(s). (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. (iii) If the facility or supplier is owned by more than one United States company ( e.g. (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. 2 (i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO 2 2 2 (ii) Annual emissions of biogenic CO 2 2 (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 2 (B) CO 2 2 2 (C) CH 4 (D) N 2 (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. Best available monitoring 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. (i) Timing of request. (ii) Content of request. (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. (3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources. (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 4 2 2 (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. (f) Verification. (g) Recordkeeping. (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. (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. 2 (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., (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., 3 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., i.e., 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., e.g., (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., (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 General. (2) Requests for extension of the use of best available monitoring methods for measurement device installation. (3) Timing of request. (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. (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. (6) Measurement device installation deadline. (7) One time extension past December 31, 2013. (k) Revised global warming potentials and special provisions for reporting year 2013 and subsequent reporting years. (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 (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 (3) Starting on January 1 of the year after the year during which the change in GWPs is published in the Federal Register (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. (1) Best available monitoring methods. Federal Register e.g., Federal Register (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. Federal Register (i) Timing of request. Federal Register (ii) Content of request. (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 (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 (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 (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. Federal Register [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] § 98.4 Authorization and responsibilities of the designated representative. (a) General. (b) Authorization of a designated representative. (c) Responsibility of the designated representative. (d) Timing. (e) Certification of the GHG emissions report. (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. (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. (h) Changes in owners and operators. (i) Certificate of representation. (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., (j) Documents of agreement. (k) Binding nature of the certificate of representation. (l) Objections concerning a designated representative. (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. (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. (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., (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. [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] § 98.5 How is the report submitted? (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. [79 FR 63780, Oct. 24, 2014, as amended at 79 FR 73778, Dec. 11, 2014; 89 FR 31891, Apr. 25, 2024] § 98.6 Definitions. All terms used in this part shall have the same meaning given in the Clean Air Act and in this section. Absorbent circulation pump Accuracy Acid Rain Program Administrator AGA Agricultural by-products Air injected flare Alkali bypass Anaerobic digester Anaerobic lagoon Anode effect Anode Effect Minutes per Cell Day (24 hours) ANSI API ASABE ASME ASTM Asphalt Aviation Gasoline B 0 4 4 Basic oxygen furnace bbl Biodiesel Biogenic CO 2 Biomass Blast furnace Blendstocks Blendstocks—Others Blowdown Blowdown vent stack 2 British Thermal Unit or Btu Bulk, 2 2 2 Bulk natural gas liquid or NGL Butane 4 10 Butylene 4 8 By-product coke oven battery Calcination Calculation methodology Calibrated bag Carbon dioxide equivalent or CO 2 e 2 Carbon dioxide production well Carbon dioxide production well facility 2 Carbon dioxide stream e.g., e.g., Carbon share Carbonate 3 −2 2 3 3 3 2 Carbonate-based mineral 3 3 2 2 3 3 2 3 2 3 3 Carbonate-based mineral mass fraction 3 3 2 2 3 3 2 3 2 3 3 Carbonate-based raw material Carbonofluoridates Catalytic cracking unit CBOB-Summer CBOB-Winter Cement kiln dust Centrifugal compressor 2 Centrifugal compressor dry seal emissions 2 Centrifugal compressor dry seals 2 Centrifugal compressor wet seal degassing vent emissions 2 Certified standards CH 4 Chemical recovery combustion unit Chemical recovery furnace Chloride process City gate CO 2 Coal see COD Cogeneration unit Coke burn-off Cokemaking Commercial applications Company records Connector Container glass Continuous bleed e.g. Continuous emission monitoring system or CEMS Continuous glass melting furnace Conventional-Summer Note: Conventional-Winter Note: Crude oil (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, Daily spread Day Decarburization vessel Deep bedding systems for cattle swine Degasification system Degradable organic carbon (DOC) Dehydrator Dehydrator vent emissions 2 Delayed coking unit delayed coking unit De-methanizer e.g., Density Desiccant Destruction (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 Destruction efficiency where: DE = Destruction Efficiency tGHG iIN tGHG iOUT Diesel—Other DIPE 3 2 3 2 Direct air capture (DAC), (1) That is deliberately released from a naturally occurring subsurface spring; or (2) Using natural photosynthesis. Direct liquefaction Direct reduction furnace Distillate fuel oil Distillate Fuel No. 1 Distillate Fuel No. 2 Distillate Fuel No. 4 DOC f Dry lot Electric arc furnace (EAF) Electric arc furnace steelmaking Electrothermic furnace Emergency generator Emergency equipment ETBE 3 3 2 Ethane 2 6 Ethanol 2 5 Ethylene 2 4 Ex refinery gate Experimental furnace Export Exporter Facility Feed Feedstock Fischer-Tropsch process Flare Flat glass Flowmeter Fluid coking unit Fluorinated acetates e.g., 2 2 Fluorinated alcohols other than fluorotelomer alcohols Fluorinated formates n Fluorinated greenhouse gas (GHG) 6 Fluorinated greenhouse gas (GHG) group (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 Fluorotelomer alcohols n 2n + 1 2 2 Fossil fuel Fractionators Fuel Fuel gas Fuel gas system Fully fluorinated GHGs 6 3 5 3 Furnace slag e.g., Gas collection system or landfill gas collection system Gas conditions Gas-fired unit Gas monitor Gas to oil ratio (GOR) Gaseous fuel Gasification Gasoline—Other Glass melting furnace Glass produced Global warming potential or GWP i.e., 2 GPA Greenhouse gas or GHG 2 4 2 GTBA 3 3 Heavy Gas Oils Heel High-bleed pneumatic devices High heat value or HHV Hydrofluorocarbons or HFCs Import (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 (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 Industrial greenhouse gases In-line kiln/raw mill Intermittent bleed pneumatic devices Isobutane 4 10 Isobutylene 4 8 Kerosene Kerosene-type jet fuel Kiln Landfill Landfill gas Liberated Lime Liquid/Slurry Low-bleed pneumatic devices Lubricants Makeup chemicals Manure composting Maximum rated heat input capacity Maximum rated input capacity Mcf Methane conversion factor 4 o Methane correction factor Methanol 3 Midgrade gasoline Miscellaneous products MMBtu Motor gasoline (finished) Mscf MTBE 3 3 3 Municipal solid waste landfill or MSW landfill Municipal solid waste or MSW Municipal wastewater treatment plant N 2 O Naphthas (<401 °F) Natural gas Natural gas driven pneumatic pump Natural gas liquids (NGLs) Natural gasoline NIST Nitric acid production line Nitrogen excreted Non-crude feedstocks Non-recovery coke oven battery North American Industry Classification System (NAICS) code(s) Federal Register http://www.census.gov/eos/www/naics/. Oil-fired unit Open-ended valve or lines (OELs) Operating hours Operational change Operator Other oils (>401 °F) Outer Continental Shelf Owner Oxygenates Pasture/Range/Paddock Pentanes plus, Perfluorocarbons or PFCs Petrochemical Petrochemical feedstocks Petroleum Petroleum coke Petroleum product Physical address, Pit storage below animal confinement (deep pits) Plant code (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 (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 Poultry manure without litter Precision Premium grade gasoline Pressed and blown glass Pressure relief device or pressure relief valve or pressure safety valve Primary fuel Process emissions 2 Process unit Process vent Propane 3 8 Propylene 3 6 Pulp mill lime kiln Pushing Raw mill RBOB-Summer RBOB-Winter Reciprocating compressor 2 Reciprocating compressor rod packing 2 Re-condenser Reformulated-Summer Reformulated-Winter Note: Regular grade gasoline Remaining 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; or (13) fluorinated GHGs with carbon-iodine bonds. Rendered animal fat, Reporting year Research and development de minimis Residual Fuel Oil No. 5 (Navy Special) Residual Fuel Oil No. 6 (a.k.a. Bunker C) Residuum Road oil Rotary lime kiln Safety device Sales oil Saturated chlorofluorocarbons (CFCs) Saturated hydrochlorofluoroethers (HCFEs) Saturated hydrofluorocarbons (HFCs) Saturated hydrofluoroethers (HFEs) Semi-refined petroleum product Sendout Sensor SF 6 Shutdown Silicon carbide Sinter process Site Smelting furnace Solid by-products Solid storage Sour gas Sour natural gas 2 2 Special naphthas Spent liquor solids Spent pulping liquor Standard conditions or standard temperature and pressure (STP), Steam reforming Still gas Storage tank Sulfur recovery plant 2 2 Supplemental fuel Supplier Sweet gas 2 2 Taconite iron ore processing TAME 3 2 2 5 3 Trace concentrations Transform Transshipment Trona 3 3 2 Ultimate analysis Unfinished oils United States United States parent company(s) Unsaturated bromochlorofluoro-carbons (BCFCs) Unsaturated bromofluorocarbons (BFCs) Unsaturated chlorofluorocarbons (CFCs) Unsaturated halogenated ethers Unsaturated hydrobromochloro-fluorocarbons (HBCFCs) Unsaturated hydrobromofluoro-carbons (HBFCs) Unsaturated hydrochlorofluorocarbons (HCFCs) Unsaturated hydrofluorocarbons (HFCs) Unsaturated perfluorocarbons (PFCs) Unstabilized crude oil Used oil e.g., etc. e.g., etc Valve Vapor recovery system Vaporization unit Vegetable oil Ventilation hole or shaft Ventilation system Volatile solids Waelz kiln Waxes Well completions Well workover Wellhead i.e. Wet natural gas Wood residuals Wool fiberglass Working capacity You Zinc smelters [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] § 98.7 What standardized methods are incorporated by reference into this part? Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register Federal Register [email protected]; www.epa.gov/dockets/epa-docket-center-reading-room. www.archives.gov/federal-register/cfr/ibr-locations [email protected]. (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 Note 1 to paragraph (e)(1): 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 (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 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 (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 (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 (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 (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 (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 (8) Protocol for Measurement of Tetrafluoromethane (CF 4 2 6 http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf (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 (10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf (11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; (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 (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 (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 (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 (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] [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] § 98.8 What are the compliance and enforcement provisions of this part? 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. § 98.9 Addresses. 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. [74 FR 56374, Oct. 30, 2009, as amended at 76 FR 73900, Nov. 29, 2011] Table A-1 to Subpart A of Part 98—Global Warming Potentials, 100-Year Time Horizon Table A-1 to Subpart A of Part 98—Global Warming Potentials, 100-Year Time Horizon Name CAS No. Chemical formula Global Chemical-Specific GWPs Carbon dioxide 124-38-9 CO 2 1 Methane 74-82-8 CH 4 a d Nitrous oxide 10024-97-2 N 2 a d Fully Fluorinated GHGs Sulfur hexafluoride 2551-62-4 SF 6 a d Trifluoromethyl sulphur pentafluoride 373-80-8 SF 5 3 d Nitrogen trifluoride 7783-54-2 NF 3 d PFC-14 (Perfluoromethane) 75-73-0 CF 4 a d PFC-116 (Perfluoroethane) 76-16-4 C 2 6 a d PFC-218 (Perfluoropropane) 76-19-7 C 3 8 a d Perfluorocyclopropane 931-91-9 c-C 3 6 d PFC-3-1-10 (Perfluorobutane) 355-25-9 C 4 10 a d PFC-318 (Perfluorocyclobutane) 115-25-3 c-C 4 8 a d Perfluorotetrahydrofuran 773-14-8 c-C 4 8 e PFC-4-1-12 (Perfluoropentane) 678-26-2 C 5 12 a d PFC-5-1-14 (Perfluorohexane, FC-72) 355-42-0 C 6 14 a d PFC-6-1-12 335-57-9 C 7 16 3 2 5 3 b PFC-7-1-18 307-34-6 C 8 18 3 2 6 3 b PFC-9-1-18 306-94-5 C 10 18 d PFPMIE (HT-70) NA CF 3 3 2 2 3 d Perfluorodecalin (cis) 60433-11-6 Z-C 10 18 b d Perfluorodecalin (trans) 60433-12-7 E-C 10 18 b d Perfluorotriethylamine 359-70-6 N(C 2 5 3 e Perfluorotripropylamine 338-83-0 N(CF 2 2 3 3 e Perfluorotributylamine 311-89-7 N(CF 2 2 2 3 3 e Perfluorotripentylamine 338-84-1 N(CF 2 2 2 2 3 3 e Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds (4s,5s)-1,1,2,2,3,3,4,5-octafluorocyclopentane 158389-18-5 trans-cyc (-CF2CF2CF2CHFCHF-) e HFC-23 75-46-7 CHF 3 a d HFC-32 75-10-5 CH 2 2 a d HFC-125 354-33-6 C 2 5 a d HFC-134 359-35-3 C 2 2 4 a d HFC-134a 811-97-2 CH 2 3 a d HFC-227ca 2252-84-8 CF 3 2 2 b HFC-227ea 431-89-0 C 3 7 a d HFC-236cb 677-56-5 CH 2 2 3 d HFC-236ea 431-63-0 CHF 2 3 d HFC-236fa 690-39-1 C 3 2 6 a d HFC-329p 375-17-7 CHF 2 2 2 3 b HFC-43-10mee 138495-42-8 CF 3 2 3 a d Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds 1,1,2,2,3,3-hexafluorocyclopentane 123768-18-3 cyc (-CF 2 2 2 2 2 e 1,1,2,2,3,3,4-heptafluorocyclopentane 15290-77-4 cyc (-CF 2 2 2 2 e HFC-41 593-53-3 CH 3 a d HFC-143 430-66-0 C 2 3 3 a d HFC-143a 420-46-2 C 2 3 3 a d HFC-152 624-72-6 CH 2 2 d HFC-152a 75-37-6 CH 3 2 a d HFC-161 353-36-6 CH 3 2 d HFC-245ca 679-86-7 C 3 3 5 a d HFC-245cb 1814-88-6 CF 3 2 3 b HFC-245ea 24270-66-4 CHF 2 2 b HFC-245eb 431-31-2 CH 2 3 b HFC-245fa 460-73-1 CHF 2 2 3 d HFC-263fb 421-07-8 CH 3 2 3 b HFC-272ca 420-45-1 CH 3 2 3 b HFC-365mfc 406-58-6 CH 3 2 2 3 d Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond HFE-125 3822-68-2 CHF 2 3 d HFE-227ea 2356-62-9 CF 3 3 d HFE-329mcc2 134769-21-4 CF 3 2 2 2 d HFE-329me3 428454-68-6 CF 3 2 3 b 1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-propane 3330-15-2 CF 3 2 2 3 b Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds HFE-134 (HG-00) 1691-17-4 CHF 2 2 d HFE-236ca 32778-11-3 CHF 2 2 2 b HFE-236ca12 (HG-10) 78522-47-1 CHF 2 2 2 d HFE-236ea2 (Desflurane) 57041-67-5 CHF 2 3 d HFE-236fa 20193-67-3 CF 3 2 3 d HFE-338mcf2 156053-88-2 CF 3 2 2 3 d HFE-338mmz1 26103-08-2 CHF 2 3 2 d HFE-338pcc13 (HG-01) 188690-78-0 CHF 2 2 2 2 d HFE-43-10pccc (H-Galden 1040x, HG-11) E1730133 CHF 2 2 2 4 2 d HCFE-235ca2 (Enflurane) 13838-16-9 CHF 2 2 b HCFE-235da2 (Isoflurane) 26675-46-7 CHF 2 3 d HG-02 205367-61-9 HF 2 2 2 2 2 b d HG-03 173350-37-3 HF 2 2 2 3 2 b d HG-20 249932-25-0 HF 2 2 2 2 b HG-21 249932-26-1 HF 2 2 2 2 2 2 b HG-30 188690-77-9 HF 2 2 3 2 b 1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,15-eicosafluoro-2,5,8,11,14-Pentaoxapentadecane 173350-38-4 HCF 2 2 2 4 2 b 1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane 84011-06-3 CHF 2 3 b Trifluoro(fluoromethoxy)methane 2261-01-0 CH 2 3 b Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds HFE-143a 421-14-7 CH 3 3 d HFE-245cb2 22410-44-2 CH 3 2 3 d HFE-245fa1 84011-15-4 CHF 2 2 3 d HFE-245fa2 1885-48-9 CHF 2 2 3 d HFE-254cb1 425-88-7 CH 3 2 2 d HFE-263fb2 460-43-5 CF 3 2 3 d HFE-263m1; R-E-143a 690-22-2 CF 3 2 3 b HFE-347mcc3 (HFE-7000) 375-03-1 CH 3 2 2 3 d HFE-347mcf2 171182-95-9 CF 3 2 2 2 d HFE-347mmy1 22052-84-2 CH 3 3 2 d HFE-347mmz1 (Sevoflurane) 28523-86-6 (CF 3 2 2 c HFE-347pcf2 406-78-0 CHF 2 2 2 3 d HFE-356mec3 382-34-3 CH 3 2 3 d HFE-356mff2 333-36-8 CF 3 2 2 3 b HFE-356mmz1 13171-18-1 (CF 3 2 3 d HFE-356pcc3 160620-20-2 CH 3 2 2 2 d HFE-356pcf2 50807-77-7 CHF 2 2 2 2 d HFE-356pcf3 35042-99-0 CHF 2 2 2 2 d HFE-365mcf2 22052-81-9 CF 3 2 2 3 b HFE-365mcf3 378-16-5 CF 3 2 2 3 d HFE-374pc2 512-51-6 CH 3 2 2 2 d HFE-449s1 (HFE-7100) Chemical blend 163702-07-6 C 4 9 3 d 163702-08-7 (CF 3 2 2 3 HFE-569sf2 (HFE-7200) Chemical blend 163702-05-4 C 4 9 2 5 d 163702-06-5 (CF 3 2 2 2 5 HFE-7300 132182-92-4 (CF 3 2 2 5 2 2 3 e HFE-7500 297730-93-9 n-C 3 7 2 5 3 2 e HG′-01 73287-23-7 CH 3 2 2 3 b HG′-02 485399-46-0 CH 3 2 2 2 3 b HG′-03 485399-48-2 CH 3 2 2 3 3 b Difluoro(methoxy)methane 359-15-9 CH 3 2 b 2-Chloro-1,1,2-trifluoro-1-methoxyethane 425-87-6 CH 3 2 b 1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane 22052-86-4 CF 3 2 2 2 3 b 2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-bis[1,2,2,2-tetrafluoro-1-(trifluoromethyl)ethyl]-furan 920979-28-8 C 12 5 19 2 b 1-Ethoxy-1,1,2,3,3,3-hexafluoropropane 380-34-7 CF 3 2 2 3 b Fluoro(methoxy)methane 460-22-0 CH 3 2 b 1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3-tetrafluoropropyl ether 60598-17-6 CHF 2 2 2 3 b d 1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane 37031-31-5 CH 2 2 2 b Difluoro(fluoromethoxy)methane 461-63-2 CH 2 2 b Fluoro(fluoromethoxy)methane 462-51-1 CH 2 2 b Saturated Chlorofluorocarbons (CFCs) E-R316c 3832-15-3 trans-cyc (-CClFCF 2 2 e Z-R316c 3934-26-7 cis-cyc (-CClFCF 2 2 e Fluorinated Formates Trifluoromethyl formate 85358-65-2 HCOOCF 3 b Perfluoroethyl formate 313064-40-3 HCOOCF 2 3 b 1,2,2,2-Tetrafluoroethyl formate 481631-19-0 HCOOCHFCF 3 b Perfluorobutyl formate 197218-56-7 HCOOCF 2 2 2 3 b Perfluoropropyl formate 271257-42-2 HCOOCF 2 2 3 b 1,1,1,3,3,3-Hexafluoropropan-2-yl formate 856766-70-6 HCOOCH(CF 3 2 b 2,2,2-Trifluoroethyl formate 32042-38-9 HCOOCH 2 3 b 3,3,3-Trifluoropropyl formate 1344118-09-7 HCOOCH 2 2 3 b Fluorinated Acetates Methyl 2,2,2-trifluoroacetate 431-47-0 CF 3 3 b 1,1-Difluoroethyl 2,2,2-trifluoroacetate 1344118-13-3 CF 3 2 3 b Difluoromethyl 2,2,2-trifluoroacetate 2024-86-4 CF 3 2 b 2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate 407-38-5 CF 3 2 3 b Methyl 2,2-difluoroacetate 433-53-4 HCF 2 3 b Perfluoroethyl acetate 343269-97-6 CH 3 2 3 b d Trifluoromethyl acetate 74123-20-9 CH 3 3 b d Perfluoropropyl acetate 1344118-10-0 CH 3 2 2 3 b d Perfluorobutyl acetate 209597-28-4 CH 3 2 2 2 3 b d Ethyl 2,2,2-trifluoroacetate 383-63-1 CF 3 2 3 b d Carbonofluoridates Methyl carbonofluoridate 1538-06-3 FCOOCH 3 b 1,1-Difluoroethyl carbonofluoridate 1344118-11-1 FCOOCF 2 3 b Fluorinated Alcohols Other Than Fluorotelomer Alcohols Bis(trifluoromethyl)-methanol 920-66-1 (CF 3 2 d 2,2,3,3,4,4,5,5-Octafluorocyclopentanol 16621-87-7 cyc (-(CF 2 4 d 2,2,3,3,3-Pentafluoropropanol 422-05-9 CF 3 2 2 d 2,2,3,3,4,4,4-Heptafluorobutan-1-ol 375-01-9 C 3 7 b d 2,2,2-Trifluoroethanol 75-89-8 CF 3 2 b 2,2,3,4,4,4-Hexafluoro-1-butanol 382-31-0 CF 3 2 2 b 2,2,3,3-Tetrafluoro-1-propanol 76-37-9 CHF 2 2 2 b 2,2-Difluoroethanol 359-13-7 CHF 2 b 2-Fluoroethanol 371-62-0 CH 2 2 b 4,4,4-Trifluorobutan-1-ol 461-18-7 CF 3 2 2 2 b Non-Cyclic, Unsaturated Perfluorocarbons (PFCs) PFC-1114; TFE 116-14-3 CF 2 2 2 4 b PFC-1216; Dyneon HFP 116-15-4 C 3 6 3 2 b Perfluorobut-2-ene 360-89-4 CF 3 3 b Perfluorobut-1-ene 357-26-6 CF 3 2 2 b Perfluorobuta-1,3-diene 685-63-2 CF 2 2 b Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs) HFC-1132a; VF2 75-38-7 C 2 2 2 2 2 b HFC-1141; VF 75-02-5 C 2 3 2 b (E)-HFC-1225ye 5595-10-8 CF 3 b (Z)-HFC-1225ye 5528-43-8 CF 3 b Solstice 1233zd(E) 102687-65-0 C 3 2 3 3 b HCFO-1233zd(Z) 99728-16-2 (Z)-CF 3 e HFC-1234yf; HFO-1234yf 754-12-1 C 3 2 4 3 2 b HFC-1234ze(E) 1645-83-6 C 3 2 4 3 b HFC-1234ze(Z) 29118-25-0 C 3 2 4 3 3 b HFC-1243zf; TFP 677-21-4 C 3 3 3 3 2 b (Z)-HFC-1336 692-49-9 CF 3 3 b HFO-1336mzz(E) 66711-86-2 (E)-CF 3 3 e HFC-1345zfc 374-27-6 C 2 5 2 b HFO-1123 359-11-5 CHF=CF 2 e HFO-1438ezy(E) 14149-41-8 (E)-(CF 3 2 e HFO-1447fz 355-08-8 CF 3 2 2 2 e Capstone 42-U 19430-93-4 C 6 3 9 3 2 3 2 b Capstone 62-U 25291-17-2 C 8 3 13 3 2 5 2 b Capstone 82-U 21652-58-4 C 10 3 17 3 2 7 2 b (e)-1-chloro-2-fluoroethene 460-16-2 (E)-CHCl = CHF e 3,3,3-trifluoro-2-(trifluoromethyl)prop-1-ene 382-10-5 (CF 3 2 2 e Non-Cyclic, Unsaturated CFCs CFC-1112 598-88-9 CClF=CClF e CFC-1112a 79-35-6 CCl 2 2 e Non-Cyclic, Unsaturated Halogenated Ethers PMVE; HFE-216 1187-93-5 CF 3 2 b Fluoroxene 406-90-6 CF 3 2 2 b Methyl-perfluoroheptene-ethers N/A CH 3 7 13 e Non-Cyclic, Unsaturated Halogenated Esters Ethenyl 2,2,2-trifluoroacetate 433-28-3 CF 3 2 e Prop-2-enyl 2,2,2-trifluoroacetate 383-67-5 CF 3 2 2 e Cyclic, Unsaturated HFCs and PFCs PFC C-1418 559-40-0 c-C 5 8 d Hexafluorocyclobutene 697-11-0 cyc (-CF=CFCF 2 2 e 1,3,3,4,4,5,5-heptafluorocyclopentene 1892-03-1 cyc (-CF 2 2 2 e 1,3,3,4,4-pentafluorocyclobutene 374-31-2 cyc (-CH=CFCF 2 2 e 3,3,4,4-tetrafluorocyclobutene 2714-38-7 cyc (-CH=CHCF 2 2 e Fluorinated Aldehydes 3,3,3-Trifluoro-propanal 460-40-2 CF 3 2 b Fluorinated Ketones Novec 1230 (perfluoro (2-methyl-3-pentanone)) 756-13-8 CF 3 2 2 b 1,1,1-trifluoropropan-2-one 421-50-1 CF 3 3 e 1,1,1-trifluorobutan-2-one 381-88-4 CF 3 2 3 e Fluorotelomer Alcohols 3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol 185689-57-0 CF 3 2 4 2 2 b 3,3,3-Trifluoropropan-1-ol 2240-88-2 CF 3 2 2 b 3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol 755-02-2 CF 3 2 6 2 2 b 3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-Nonadecafluoroundecan-1-ol 87017-97-8 CF 3 2 8 2 2 b Fluorinated GHGs With Carbon-Iodine Bond(s) Trifluoroiodomethane 2314-97-8 CF 3 b Remaining Fluorinated GHGs with Chemical-Specific GWPs Dibromodifluoromethane (Halon 1202) 75-61-6 CBr 2 2 b 2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-2311/Halothane) 151-67-7 CHBrClCF 3 b Heptafluoroisobutyronitrile 42532-60-5 (CF 3 2 e Carbonyl fluoride 353-50-4 COF 2 e Fluorinated GHG group f Global warming Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not Listed Above Fully fluorinated GHGs g 9,200 Saturated hydrofluorocarbons (HFCs) with 2 or fewer carbon-hydrogen bonds g 3,000 Saturated HFCs with 3 or more carbon-hydrogen bonds g 840 Saturated hydrofluoroethers (HFEs) and hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen bond g 6,600 Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds g 2,900 Saturated HFEs and HCFEs with 3 or more carbon-hydrogen bonds g 320 Saturated chlorofluorocarbons (CFCs) g 4,900 Fluorinated formates 350 Cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons (BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated hydrobromofluorocarbons (HBFCs), unsaturated hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers, and unsaturated halogenated esters g 58 Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols g 25 Fluorinated aldehydes, fluorinated ketones, and non-cyclic forms of the following: unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs, unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers and unsaturated halogenated esters g 1 Fluorotelomer alcohols g 1 Fluorinated GHGs with carbon-iodine bond(s) g 1 Other fluorinated GHGs g 1,800 a b c d e f g [89 FR 31894, Apr. 25, 2024] Table A-2 to Subpart A of Part 98—Units of Measure Conversions To convert from To Multiply by Kilograms (kg) Pounds (lbs) 2.20462 Pounds (lbs) Kilograms (kg) 0.45359 Pounds (lbs) Metric tons 4.53592 × 10 −4 Short tons Pounds (lbs) 2,000 Short tons Metric tons 0.90718 Metric tons Short tons 1.10231 Metric tons Kilograms (kg) 1,000 Cubic meters (m 3 Cubic feet (ft 3 35.31467 Cubic feet (ft 3 Cubic meters (m 3 0.028317 Gallons (liquid, US) Liters (l) 3.78541 Liters (l) Gallons (liquid, US) 0.26417 Barrels of Liquid Fuel (bbl) Cubic meters (m 3 0.15891 Cubic meters (m 3 Barrels of Liquid Fuel (bbl) 6.289 Barrels of Liquid Fuel (bbl) Gallons (liquid, US) 42 Gallons (liquid, US) Barrels of Liquid Fuel (bbl) 0.023810 Gallons (liquid, US) Cubic meters (m 3 0.0037854 Liters (l) Cubic meters (m 3 0.001 Feet (ft) Meters (m) 0.3048 Meters (m) Feet (ft) 3.28084 Miles (mi) Kilometers (km) 1.60934 Kilometers (km) Miles (mi) 0.62137 Square feet (ft 2 Acres 2.29568 × 10 −5 Square meters (m 2 Acres 2.47105 × 10 −4 Square miles (mi 2 Square kilometers (km 2 2.58999 Degrees Celsius (°C) Degrees Fahrenheit (°F) °C = ( 5 9 Degrees Fahrenheit (°F) Degrees Celsius (°C) °F = ( 9 5 Degrees Celsius (°C) Kelvin (K) K = °C + 273.15 Kelvin (K) Degrees Rankine (°R) 1.8 Joules Btu 9.47817 × 10 −4 Btu MMBtu 1 × 10 −6 Pascals (Pa) Inches of Mercury (in Hg) 2.95334 × 10 −4 Inches of Mercury (inHg) Pounds per square inch (psi) 0.49110 Pounds per square inch (psi) Inches of Mercury (in Hg) 2.03625 Table A-3 to Subpart A of Part 98—Source Category List for § 98.2( a Table A-3 to Subpart A of Part 98—Source Category List for § 98.2 (a) Source Categories a Electricity generation units that report CO 2 Adipic acid production (subpart E of this part). Aluminum production (subpart F of this part). Ammonia manufacturing (subpart G of this part). Cement production (subpart H of this part). HCFC-22 production (subpart O of this part). HFC-23 destruction processes that are not collocated with a HCFC-22 production facility and that destroy more than 2.14 metric tons of HFC-23 per year (subpart O of this part). Lime manufacturing (subpart S of this part). Nitric acid production (subpart V of this part). Petrochemical production (subpart X of this part). Petroleum refineries (subpart Y of this part). Phosphoric acid production (subpart Z of this part). Silicon carbide production (subpart BB of this part). Soda ash production (subpart CC of this part). Titanium dioxide production (subpart EE of this part). Municipal solid waste landfills that generate CH 4 2 Manure management systems with combined CH 4 2 2 Additional Source Categories a Electrical transmission and distribution equipment use at facilities where the total estimated emissions from fluorinated GHGs, as determined under § 98.301 (subpart DD of this part), are equivalent to 25,000 metric tons CO 2 Underground coal mines liberating 36,500,000 actual cubic feet of CH 4 Geologic sequestration of carbon dioxide (subpart RR of this part). Injection of carbon dioxide (subpart UU of this part). Additional Source Categories a Geologic sequestration of carbon dioxide with enhanced oil recovery using ISO 27916 (subpart VV of this part). Coke calciners (subpart WW of this part). Calcium carbide production (subpart XX of this part). Caprolactam, glyoxal, and glyoxylic acid production (subpart YY of this part). a [75 FR 39760, July 12, 2010, as amended at 75 FR 74817, 75078, Dec. 1, 2010; 76 FR 73900, Nov. 29, 2011; 81 FR 89250, Dec. 9, 2016; 89 FR 31899, Apr. 25, 2024] Table A-4 to Subpart A of Part 98—Source Category List for § 98.2( a Table A-4 to Subpart A of Part 98—Source Category List for § 98.2 (a) Source Categories a Ferroalloy production (subpart K of this part). Glass production (subpart N of this part). Hydrogen production (subpart P of this part). Iron and steel production (subpart Q of this part). Lead production (subpart R of this part). Pulp and paper manufacturing (subpart AA of this part). Zinc production (subpart GG of this part). Additional Source Categories a Electronics manufacturing (subpart I of this part). Fluorinated gas production (subpart L of this part). Magnesium production (subpart T of this part). Petroleum and Natural Gas Systems (subpart W of this part). Industrial wastewater treatment (subpart II of this part). Electrical transmission and distribution equipment manufacture or refurbishment, as determined under § 98.451 (subpart SS of this part). Industrial waste landfills (subpart TT of this part). Additional Source Categories a Ceramics manufacturing facilities, as determined under § 98.520 (subpart ZZ of this part). a [75 FR 39760, July 12, 2010, as amended at 75 FR 74488, Nov. 30, 2010; 75 FR 74817, Dec. 1, 2010; 81 FR 89250, Dec. 9, 2016; 89 FR 31899, Apr. 25, 2024] Table A-5 to Subpart A of Part 98—Supplier Category List for § 98.2( a Supplier Categories a Coal-to-liquids suppliers (subpart LL): (A) All producers of coal-to-liquid products. (B) Importers of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO 2 (C) Exporters of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO 2 Petroleum product suppliers (subpart MM): (A) All petroleum refineries that distill crude oil. (B) Importers of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO 2 (C) Exporters of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO 2 Natural gas and natural gas liquids suppliers (subpart NN): (A) All fractionators. (B) Local natural gas distribution companies that deliver 460,000 thousand standard cubic feet or more of natural gas per year. Industrial greenhouse gas suppliers (subpart OO): (A) All producers of industrial greenhouse gases. (B) Importers of industrial greenhouse gases with annual bulk imports of N 2 2 2 (C) Exporters of industrial greenhouse gases with annual bulk exports of N 2 2 2 (D) Starting with reporting year 2018, all producers of fluorinated heat transfer fluids. (E) Starting with reporting year 2018, importers of fluorinated heat transfer fluids with annual bulk imports of N 2 2 2 (F) Starting with reporting year 2018, exporters of fluorinated heat transfer fluids with annual bulk exports of N 2 2 2 (G) Starting with reporting year 2018, facilities that destroy 25,000 mtCO 2 Carbon dioxide suppliers (subpart PP): (A) All producers of CO 2 (B) Importers of CO 2 2 2 2 (C) Exporters of CO 2 2 2 2 Additional Supplier Categories Applicable a Importers and exporters of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams (subpart QQ): (A) Importers of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO 2 (B) Exporters of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO 2 a [75 FR 39760, July 12, 2010, as amended at 75 FR 74817, Dec. 1, 2010; 75 FR 79140, Dec. 17, 2010; 76 FR 73901, Nov. 29, 2011; 81 FR 89250, Dec. 9, 2016] Table A-6 to Subpart A of Part 98—Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2013 Subpart Rule citation Specific data elements for which reporting date is March 31, 2013 (“All” means all data elements in the cited paragraph are not required to be reported until March 31, 2013) C 98.36(d)(1)(iv) All. C 98.36(d)(2)(ii)(G) All. C 98.36(d)(2)(iii)(G) All. C 98.36(e)(2)(iv)(G) All. C 98.36(e)(2)(viii)(A) All. C 98.36(e)(2)(viii)(B) All. C 98.36(e)(2)(viii)(C) All. C 98.36(e)(2)(x)(A) All. C 98.36(e)(2)(xi) All. DD 98.306(a)(2) All. DD 98.306(a)(3) All. DD 98.306(d) All. DD 98.306(e) All. DD 98.306(f) All. DD 98.306(g) All. DD 98.306(h) All. DD 98.306(i) All. DD 98.306(j) All. DD 98.306(k) All. DD 98.306(l) All. FF 98.326(a) All. FF 98.326(b) All. FF 98.326(c) All. FF 98.326(f) Only quarterly volumetric flow rate. FF 98.326(g) Only quarterly CH 4 FF 98.326(h) Only weekly volumetric flow used to calculate CH 4 FF 98.326(j) All. FF 98.326(k) All. FF 98.326(o) All. FF 98.326(p) Only assumed destruction efficiency for the primary destruction device and assumed destruction efficiency for the backup destruction device. HH 98.346(a) Only year in which landfill first accepted waste, last year the landfill accepted waste (if used as an input in Equation HH-3), capacity of the landfill (if used as an input in Equation HH-3), and waste disposal quantity for each year of landfilling. HH 98.346(b) Only quantity of waste determined using the methods in § 98.343(a)(3)(i), quantity of waste determined using the methods in § 98.343(a)(3)(ii), population served by the landfill for each year, and the value of landfill capacity (LFC) used in the calculation. HH 98.346(c) All. HH 98.346(d)(1) Only degradable organic carbon (DOC) value, and fraction of DOC dissimilated (DOCF) values. HH 98.346(d)(2) All. HH 98.346(e) Only fraction of CH 4 HH 98.346(f) Only surface area associated with each cover type. HH 98.346(g) All. HH 98.346(i)(5) Only annual operating hours for the destruction devices located at the landfill facility, and the destruction efficiency for the destruction devices associated with that measurement location. HH 98.346(i)(6) All. HH 98.346(i)(7) Only surface area specified in Table HH-3, estimated gas collection system efficiency, and annual operating hours of the gas collection system for each measurement locations. HH 98.346(i)(9) Only CH 4 II 98.356(b)(1) All. II 98.356(b)(2) All. II 98.356(b)(3) All. II 98.356(b)(4) All. II 98.356(b)(5) All. II 98.356(d)(1) All. II 98.356(d)(7) All. II 98.356(d)(8) Only annual operating hours for the primary destruction device, annual operating hours for the backup destruction device, destruction efficiency of the primary destruction device, and destruction efficiency of the backup destruction device. SS 98.456(a) All. SS 98.456(b) All. SS 98.456(c) All. SS 98.456(d) All. SS 98.456(e) All. SS 98.456(f) All. SS 98.456(g) All. SS 98.456(h) All. SS 98.456(i) All. SS 98.456(j) All. SS 98.456(m) All. SS 98.456(n) All. SS 98.456(o) All. SS 98.456(q) All. SS 98.456(r) All. SS 98.456(s) All. SS 98.456(t) Only for any missing data the substitute parameters used to estimate emissions in their absence. TT 98.466(a)(2) All. TT 98.466(a)(3) Only last year the landfill accepted waste (for closed landfills using Equation TT-4). TT 98.466(a)(4) Only capacity of the landfill in metric tons (for closed landfills using Equation TT-4). TT 98.466(b)(3) Only fraction of CH 4 TT 98.466(b)(4) Only the methane correction factor (MCF) value used in the calculations. TT 98.466(c)(4)(i) All. TT 98.466(c)(4)(ii) All. TT 98.466(c)(4)(iii) All. TT 98.466(d)(2) All. TT 98.466(d)(3) Only degradable organic carbon (DOCx) value for each waste stream used in calculations. TT 98.466(e)(2) Only surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type (for facilities using a landfill gas collection system). TT 98.466(f) All. [76 FR 53065, Aug. 25, 2011, as amended at 77 FR 48088, Aug. 13, 2012; 78 FR 71949, Nov. 29, 2013] Table A-7 to Subpart A of Part 98—Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2015 Subpart Rule citation Specific data elements for which reporting date is March 31, 2015 A 98.3(d)(3)(v) All. a C 98.36(b)(9)(iii) Only estimate of the heat input. a C 98.36(c)(2)(ix) Only estimate of the heat input from each type of fuel listed in Table C-2. a C 98.36(e)(2)(i) All. a C 98.36(e)(2)(ii)(A) All. a C 98.36(e)(2)(ii)(C) Only HHV value for each calendar month in which HHV determination is required. a C 98.36(e)(2)(ii)(D) All. a C 98.36(e)(2)(iv)(A) All. a C 98.36(e)(2)(iv)(C) All. a C 98.36(e)(2)(iv)(F) All. a C 98.36(e)(2)(ix)(D) All. a C 98.36(e)(2)(ix)(E) All. a C 98.36(e)(2)(ix)(F) All. a E 98.56(g) All. E 98.56(h) All. E 98.56(j)(4) All. E 98.56(j)(5) All. E 98.56(j)(6) All. E 98.56(l) All. H 98.86(b)(11) All. H 98.86(b)(13) Name of raw kiln feed or raw material. O 98.156(d)(2) All. O 98.156(d)(3) All. O 98.156(d)(4) All. Q 98.176(f)(1) All. W 98.236(c)(1)(i) All. W 98.236(c)(1)(ii) All. W 98.236(c)(1)(iii) All. W 98.236(c)(2)(i) All. W 98.236(c)(3)(i) All. W 98.236(c)(3)(ii) Only Calculation Methodology 2. W 98.236(c)(3)(iii) All. W 98.236(c)(3)(iv) All. W 98.236(c)(4)(i)(A) All. W 98.236(c)(4)(i)(B) All. W 98.236(c)(4)(i)(C) All. W 98.236(c)(4)(i)(D) All. W 98.236(c)(4)(i)(E) All. W 98.236(c)(4)(i)(F) All. W 98.236(c)(4)(i)(G) All. W 98.236(c)(4)(i)(H) All. W 98.236(c)(4)(ii)(A) All. W 98.236(c)(5)(i)(D) All. W 98.236(c)(5)(ii)(C) All. W 98.236(c)(6)(i)(B) All. b W 98.236(c)(6)(i)(D) All. b W 98.236(c)(6)(i)(E) All. b W 98.236(c)(6)(i)(F) All. b W 98.236(c)(6)(i)(G) Only the amount of natural gas required. W 98.236(c)(6)(i)(H) Only the amount of natural gas required. W 98.236(c)(6)(ii)(A) All. W 98.236(c)(6)(ii)(B) All. W 98.236(c)(7)(i)(A) Only for Equation W-14A. W 98.236(c)(8)(i)(F) All. b W 98.236(c)(8)(i)(K) All. W 98.236(c)(8)(ii)(A) All. b W 98.236(c)(8)(ii)(H) All. W 98.236(c)(8)(iii)(A) All. W 98.236(c)(8)(iii)(B) All. W 98.236(c)(8)(iii)(G) All. W 98.236(c)(12)(ii) All. W 98.236(c)(12)(v) All. W 98.236(c)(13)(i)(E) All. W 98.236(c)(13)(i)(F) All. W 98.236(c)(13)(ii)(A) All. W 98.236(c)(13)(ii)(B) All. W 98.236(c)(13)(iii)(A) All. W 98.236(c)(13)(iii)(B) All. W 98.236(c)(13)(v)(A) All. W 98.236(c)(14)(i)(B) All. W 98.236(c)(14)(ii)(A) All. W 98.236(c)(14)(ii)(B) All. W 98.236(c)(14)(iii)(A) All. W 98.236(c)(14)(iii)(B) All. W 98.236(c)(14)(v)(A) All. W 98.236(c)(15)(ii)(A) All. W 98.236(c)(15)(ii)(B) All. W 98.236(c)(16)(viii) All. W 98.236(c)(16)(ix) All. W 98.236(c)(16)(x) All. W 98.236(c)(16)(xi) All. W 98.236(c)(16)(xii) All. W 98.236(c)(16)(xiii) All. W 98.236(c)(16)(xiv) All. W 98.236(c)(16)(xv) All. W 98.236(c)(16)(xvi) All. W 98.236(c)(17)(ii) All. W 98.236(c)(17)(iii) All. W 98.236(c)(17)(iv) All. W 98.236(c)(18)(i) All. W 98.236(c)(18)(ii) All. W 98.236(c)(19)(iv) All. W 98.236(c)(19)(vii) All. Y 98.256(h)(5)(i) Only value of the correction. Y 98.256(k)(4) Only mole fraction of methane in coking gas. Y 98.256(n)(3) All (if used in Equation Y-21 to calculate emissions from equipment leaks). Y 98.256(o)(4)(vi) Only tank-specific methane composition data and gas generation rate data. AA 98.276(e) All. CC 98.296(b)(10)(i) All. CC 98.296(b)(10)(ii) All. CC 98.296(b)(10)(iii) All. CC 98.296(b)(10)(iv) All. CC 98.296(b)(10)(v) All. CC 98.296(b)(10)(vi) All. II 98.356(d)(2) All (if conducting weekly sampling). II 98.356(d)(3) All (if conducting weekly sampling). II 98.356(d)(4) Only weekly average temperature (if conducting weekly sampling). II 98.356(d)(5) Only weekly average moisture content (if conducting weekly sampling). II 98.356(d)(6) Only weekly average pressure (if conducting weekly sampling). a e.g., e.g., b [79 FR 73783, Dec. 11, 2014] Subpart B [Reserved] Subpart C—General Stationary Fuel Combustion Sources § 98.30 Definition of the source category. (a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process heaters. (b) This source category does not include: (1) Portable equipment, as defined in § 98.6. (2) Emergency generators and emergency equipment, as defined in § 98.6. (3) Irrigation pumps at agricultural operations. (4) Flares, unless otherwise required by provisions of another subpart of this part to use methodologies in this subpart. (5) Electricity generating units that are subject to subpart D of this part. (c) For a unit that combusts hazardous waste (as defined in § 261.3 of this chapter), reporting of GHG emissions is not required unless either of the following conditions apply: (1) Continuous emission monitors (CEMS) are used to quantify CO 2 (2) Any fuel listed in Table C-1 of this subpart is also combusted in the unit. In this case, report GHG emissions from combustion of all fuels listed in Table C-1 of this subpart. (d) You are not required to report GHG emissions from pilot lights. A pilot light is a small auxiliary flame that ignites the burner of a combustion device when the control valve opens. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79140, Dec. 17, 2010] § 98.31 Reporting threshold. You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either §§ 98.2(a)(1), 98.2(a)(2), or 98.2(a)(3). § 98.32 GHGs to report. You must report CO 2 4 2 [75 FR 79140, Dec. 17, 2010] § 98.33 Calculating GHG emissions. You must calculate CO 2 4 2 (a) CO 2 emissions from fuel combustion. 2 2 2 (1) Tier 1 Calculation Methodology. 2 (i) Use Equation C-1 except when natural gas billing records are used to quantify fuel usage and gas consumption is expressed in units of therms or million Btu. In that case, use Equation C-1a or C-1b, as applicable. where: CO 2 2 Fuel = Mass or volume of fuel combusted per year, from company records as defined in § 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). HHV = Default high heat value of the fuel, from Table C-1 of this subpart (mmBtu per mass or mmBtu per volume, as applicable). EF = Fuel-specific default CO 2 2 1 × 10 −3 (ii) If natural gas consumption is obtained from billing records and fuel usage is expressed in therms, use Equation C-1a. where: CO 2 2 Gas = Annual natural gas usage, from billing records (therms). EF = Fuel-specific default CO 2 2 0.1 = Conversion factor from therms to mmBtu 1 × 10 −3 (iii) If natural gas consumption is obtained from billing records and fuel usage is expressed in mmBtu, use Equation C-1b. where: CO 2 2 Gas = Annual natural gas usage, from billing records (mmBtu). EF = Fuel-specific default CO 2 2 1 × 10 −3 (2) Tier 2 Calculation Methodology. 2 (i) Equation C-2a of this section applies to any type of fuel listed in Table C-1 of the subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C-2c of this section. Where: CO 2 2 Fuel = Mass or volume of the fuel combusted during the year, from company records as defined in § 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). HHV = Annual average high heat value of the fuel (mmBtu per mass or volume). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section. EF = Fuel-specific default CO 2 2 1 × 10 −3 (ii) The minimum required sampling frequency for determining the annual average HHV ( e.g., (A) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of units that includes at least one unit of that size), the annual average HHV shall be calculated using Equation C-2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically. Where: (HHV) annual (HHV) I (Fuel) I e.g., e.g., n = Number of sample periods in the year. (B) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the HHV sampling frequency, the annual average HHV shall either be computed according to paragraph (a)(2)(ii)(A) of this section or as the arithmetic average HHV for all values for the year (including valid samples and substitute data values under § 98.35). (iii) For units that combust municipal solid waste (MSW) and that produce steam, use Equation C-2c of this section. Equation C-2c of this section may also be used for any other solid fuel listed in Table C-1 of this subpart provided that steam is generated by the unit. Where: CO 2 2 Steam = Total mass of steam generated by MSW or solid fuel combustion during the reporting year (lb steam). B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam output capacity (mmBtu/lb steam). EF = Fuel-specific default CO 2 2 1 × 10 −3 (3) Tier 3 Calculation Methodology. 2 (i) For a solid fuel, use Equation C-3 of this section. Where: CO 2 2 Fuel = Annual mass of the solid fuel combusted, from company records as defined in § 98.6 (short tons). CC = Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO 2 0.91 = Conversion factor from short tons to metric tons. (ii) For a liquid fuel, use Equation C-4 of this section. Where: CO 2 2 Fuel = Annual volume of the liquid fuel combusted (gallons). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to § 98.3(i). Fuel billing meters may be used for this purpose. Tank drop measurements may also be used. CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. (iii) For a gaseous fuel, use equation C-5 to this section. Where: CO 2 2 Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to § 98.3(i). Fuel billing meters may be used for this purpose. CC = Annual average carbon content of the gaseous fuel (kg C per kg of fuel). The annual average carbon content shall be determined using the procedures specified in paragraphs (a)(3)(iii)(A)( 1 2 MW = Annual average molecular weight of the gaseous fuel (kg per kg-mole). The annual average molecular weight shall be determined using the procedures specified in paragraphs (a)(3)(iii)(B)( 1 2 MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg mole if you select 68 °F as standard temperature and 836.6 scf per kg mole if you select 60 °F as standard temperature. 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. (A) The minimum required sampling frequency for determining the annual average carbon content ( e.g., 1 2 ( 1 Where: (CC) annual (CC) i (Fuel) i e.g., (MW) i MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg-mole if you select 68 °F as standard temperature and 836.6 scf per kg-mole if you select 60 °F as standard temperature. n = Number of sample periods in the year. ( 2 1 (B) The minimum required sampling frequency for determining the annual average molecular weight ( e.g., 1 2 ( 1 Where: (MW) annual (MW) i (Fuel) i e.g., MVC = Molar volume conversion factor at standard conditions, as defined in § 98.6. Use 849.5 scf per kg-mole if you select 68 °F as standard temperature and 836.6 scf per kg-mole if you select 60 °F as standard temperature. n = Number of sample periods in the year. ( 2 1 (iv) Fuel flow meters that measure mass flow rates may be used for liquid or gaseous fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content. You must measure the density using one of the following appropriate methods. You may use a method published by a consensus-based standards organization, if such a method exists, or you may use industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (v) The following default density values may be used for fuel oil, in lieu of using the methods in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil. (4) Tier 4 Calculation Methodology. 2 (i) This methodology requires a CO 2 2 2 (ii) When the CO 2 2 Where: CO 2 2 C CO2 2 2 Q = Hourly average stack gas volumetric flow rate (scfh). 5.18 × 10 −7 2 (iii) If the CO 2 2 where: CO 2 2 CO 2 2 %H 2 (iv) An oxygen (O 2 2 2 i.e., 2 2 2 (v) Each hourly CO 2 (vi) The hourly CO 2 2 (vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO 2 (viii) If a portion of the flue gases generated by a unit subject to Tier 4 ( e.g., 2 2 (A) At least once a year, use EPA Methods 2 and 3A, and (if necessary) Method 4 in appendices A-2 and A-3 to part 60 of this chapter to perform emissions testing at a set point that best represents normal, stable process operating conditions. A minimum of three one-hour Method 3A tests are required, to determine the CO 2 e.g., etc. (B) Calculate a CO 2 CO2 2 2 2 (C) The results of each annual stack test shall be used in the GHG emissions calculations for the year of the test. (D) If, for the majority of the operating hours during the year, the diverted stream is withdrawn at a steady rate at or near the tested set point (as evidenced by fan and damper settings and/or other parameters), you may use the calculated CO 2 2 (E) If the flow rate of the diverted stream varies significantly throughout the year, except as provided below, repeat the stack test and emission rate calculation procedures described in paragraphs (c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two more set points across the range of typical operating conditions to develop a correlation between CO 2 2 2 (F) Calculate the annual CO 2 2 2 2 (G) Finally, add the CO 2 2 2 (H) The exact method and procedures used to estimate the CO 2 (5) Alternative methods for certain units subject to Part 75 of this chapter. (i) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to appendix D to part 75 of this chapter, but is not required by the applicable part 75 program to report CO 2 2 (A) Use the hourly heat input data from appendix D to part 75 of this chapter, together with Equation G-4 in appendix G to part 75 of this chapter to determine the hourly CO 2 (B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO 2 (C) Divide the cumulative annual CO 2 (ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to § 75.19 of this chapter but is not required by the applicable part 75 program to report CO 2 2 (A) Calculate the hourly CO 2 (B) Sum the hourly CO 2 2 (C) Divide the cumulative annual CO 2 (iii) For a unit that is not subject to subpart D of this part, uses flow rate and CO 2 2 2 2 (A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 75 of this chapter to calculate the hourly CO 2 2 2 2 (B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO 2 (C) Divide the cumulative annual CO 2 (iv) For units that qualify to use the alternative CO 2 2 (b) Use of the four tiers. 2 (1) The Tier 1 Calculation Methodology: (i) May be used for any fuel listed in Table C-1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less. (ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required. (iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C-1 of this subpart. (iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in § 98.34(a), or at a greater frequency. In such cases, Tier 2 shall be used. This restriction does not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and (b)(1)(vii) of this section. (v) May be used for natural gas combustion in a unit of any size, in cases where the annual natural gas consumption is obtained from fuel billing records in units of therms or mmBtu. (vi) May be used for MSW combustion in a small, batch incinerator that burns no more than 1,000 tons per year of MSW. (vii) May be used for the combustion of MSW and/or tires in a unit, provided that no more than 10 percent of the unit's annual heat input is derived from those fuels, combined. (viii) May be used for the combustion of a fuel listed in Table C-1 if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply: (A) The use of Tier 4 is not required. (B) The fuel provides less than 10 percent of the annual heat input to the unit, or if § 98.36(c)(3) applies, to the group of units served by a common supply pipe. (2) The Tier 2 Calculation Methodology: (i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of this subpart. (ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of natural gas and/or distillate fuel oil. (iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required. (3) The Tier 3 Calculation Methodology: (i) May be used for a unit of any size that combusts any type of fuel listed in Table C-1 of this subpart (except for MSW), unless the use of Tier 4 is required. (ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C-1 of this subpart (except MSW), unless either of the following conditions apply: (A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section. (B) The use of Tier 4 is required. (iii) Shall be used for a fuel not listed in Table C-1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply: (A) The use of Tier 4 is not required. (B) The fuel provides 10% or more of the annual heat input to the unit or, if § 98.36(c)(3) applies, to the group of units served by a common supply pipe. (iv) Shall be used when specified in another applicable subpart of this part, regardless of unit size. (4) The Tier 4 Calculation Methodology: (i) May be used for a unit of any size, combusting any type of fuel. Tier 4 may also be used for any group of stationary fuel combustion units, process units, or manufacturing units that share a common stack or duct. (ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this section: (A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 600 tons per day of MSW. (B) The unit combusts solid fossil fuel or MSW as the primary fuel. (C) The unit has operated for more than 1,000 hours in any calendar year since 2005. (D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit's operating permit. (E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified, either in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program. (F) The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit's operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program. (iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 600 tons of MSW per day or less, if the unit meets all of the following three conditions: (A) The unit has both a stack gas volumetric flow rate monitor and a CO 2 (B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this section. (C) The CO 2 (iv) May apply to common stack or duct configurations where: (A) The combined effluent gas streams from two or more stationary fuel combustion units are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if all of the conditions in paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in paragraph (b)(4)(iv)(A)(2) of this section are met. ( 1 ( 2 (B) The combined effluent gas streams from a process or manufacturing unit and a stationary fuel combustion unit are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if the combustion unit and the monitors installed at the common stack or duct meet the applicability criteria specified in paragraph (b)(4)(iv)(A)( 1 2 (C) The combined effluent gas streams from two or more manufacturing or process units are vented through a common stack or duct. In this case, if any of the units is required by an applicable subpart of this part to use Tier 4, the CO 2 2 2 (5) The Tier 4 Calculation Methodology shall be used: (i) Starting on January 1, 2010, for a unit that is required to report CO 2 2 (ii) No later than January 1, 2011, for a unit that is required to report CO 2 2 2 (A) The certification tests are passed in sequence, with no test failures. (B) No unscheduled maintenance or repair of the CEMS is performed during the certification test period. (iii) No later than 180 days following the date on which a change is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or (b)(4)(iii) of this section ( e.g., (6) You may elect to use any applicable higher tier for one or more of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units that use either the Tier 4 or the alternative calculation methodology specified in paragraph (a)(5)(iii) of this section, CO 2 (c) Calculation of CH 4 and N 2 O emissions from stationary combustion sources. 4 2 2 (1) Use Equation C-8 of this section to estimate CH 4 2 2 Where: CH 4 2 4 2 Fuel = Mass or volume of the fuel combusted, either from company records or directly measured by a fuel flow meter, as applicable (mass or volume per year). HHV = Default high heat value of the fuel from Table C-1 of this subpart; alternatively, for Tier 3, if actual HHV data are available for the reporting year, you may average these data using the procedures specified in paragraph (a)(2)(ii) of this section, and use the average value in Equation C-8 (mmBtu per mass or volume). EF = Fuel-specific default emission factor for CH 4 2 4 2 4 1 × 10 −3 (i) Use Equation C-8a to calculate CH 4 2 where: CH 4 2 4 2 Fuel = Annual natural gas usage, from gas billing records (therms). EF = Fuel-specific default emission factor for CH 4 2 4 2 4 0.1 = Conversion factor from therms to mmBtu 1 × 10 −3 (ii) Use Equation C-8b to calculate CH 4 2 CH 4 N 2 O −3 Fuel EF where: CH 4 2 4 2 Fuel = Annual natural gas usage, from gas billing records (mmBtu). EF = Fuel-specific default emission factor for CH 4 2 4 2 4 1 × 10 −3 (2) Use Equation C-9a of this section to estimate CH 4 2 2 Where: CH 4 2 4 2 Fuel = Mass or volume of the fuel combusted during the reporting year. HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (mmBtu per mass or volume). EF = Fuel-specific default emission factor for CH 4 2 4 2 4 1 × 10 −3 (3) Use Equation C-9b of this section to estimate CH 4 2 2 Where: CH 4 2 4 2 Steam = Total mass of steam generated by solid fuel combustion during the reporting year (lb steam). B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam output (mmBtu/lb steam). EF = Fuel-specific emission factor for CH 4 2 4 2 1 × 10 −3 (4) Use Equation C-10 of this section for: units subject to subpart D of this part; units that qualify for and elect to use the alternative CO 2 Where: CH 4 2 4 2 (HI) A EF = Fuel-specific default emission factor for CH 4 2 4 2 4 0.001 = Conversion factor from kg to metric tons. (i) If only one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, substitute the cumulative annual heat input from combustion of the fuel into Equation C-10 of this section to calculate the annual CH 4 2 A (ii) If more than one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, use Equation C-10 of this section separately for each type of fuel, except as provided in paragraph (c)(4)(ii)(B) of this section. Determine the appropriate values of (HI) A (A) For units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter, obtain (HI) A (B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this chapter, the value of (HI) A (C) For Tier 4 units, use the best available information ( e.g., A (D) Units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter may use the best available information described in paragraph (c)(4)(ii)(C) of this section, to estimate (HI) A (5) When multiple fuels are combusted during the reporting year, sum the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-9b, or C-10 of this section (as applicable) to obtain the total annual CH 4 2 (6) Calculate the annual CH 4 2 (i) If the mass, volume, or heat input of each component fuel in the blend is determined before the fuels are mixed and combusted, calculate and report CH 4 2 (ii) If the mass, volume, or heat input of each component fuel in the blend is not determined before the fuels are mixed and combusted, a reasonable estimate of the percentage composition of the blend, based on best available information, is required. Perform the following calculations for each component fuel “i” that is listed in table C-2 to this subpart: (A) Multiply (% Fuel)i, the estimated mass, volume, or heat input percentage of component fuel “i” (expressed as a decimal fraction), by the total annual mass, volume, or heat input of the blended fuel combusted during the reporting year, to obtain an estimate of the annual value for component “i”; (B) [Reserved] (C) Calculate the annual CH 4 2 (D) Sum the annual CH 4 4 2 2 (d) Calculation of CO 2 from sorbent. 2 2 2 3 S Where: CO 2 2 S = Limestone or other sorbent used in the reporting year, from company records (short tons). R = The number of moles of CO 2 3 2 MW CO2 MW S 0.91 = Conversion factor from short tons to metric tons. (2) The total annual CO 2 2 2 (e) Biogenic CO 2 emissions from combustion of biomass with other fuels. 2 i.e., 2 2 2 2 2 2 (1) You may use equation C-1 to this section to calculate the annual CO 2 2 (i) Company records. (ii) The procedures in paragraph (e)(4) of this section. (iii) The best available information for premixed fuels that contain biomass and fossil fuels ( e.g., (2) You may use the procedures of this paragraph if the following three conditions are met: First, a CO 2 2 2 2 i.e., (i) For each operating hour, use Equation C-12 of this section to determine the volume of CO 2 Where: V CO2h 2 (%CO 2 h 2 2 2 2 Q h t h 100 = Conversion factor from percent to a decimal fraction. (ii) Sum all of the hourly V CO2h total 2 (iii) Calculate the annual volume of CO 2 Where: V ff 2 Fuel = Total quantity of the fossil fuel combusted in the reporting year, from company records, as defined in § 98.6 (lb for solid fuel, gallons for liquid fuel, and scf for gaseous fuel). F c 2 HHV = High heat value of the fossil fuel, from fuel sampling and analysis (annual average value in Btu/lb for solid fuel, Btu/gal for liquid fuel and Btu/scf for gaseous fuel, sampled as specified (e.g., monthly, quarterly, semi-annually, or by lot) in § 98.34(a)(2)). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section. 10 6 (iv) Subtract V ff total bio 2 (v) Calculate the biogenic percentage of the annual CO 2 (vi) Calculate the annual biogenic CO 2 2 (A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation Methodology. (B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph (a)(5)(iii). (C) From the electronic data report required under § 75.64 of this chapter, for units in the Acid Rain Program and other units using CEMS to monitor and report CO 2 2 2 (3) You must use the procedures in paragraphs (e)(3)(i) through (iii) of this section to determine the annual biogenic CO 2 2 (i) Use an applicable CO 2 2 (ii) Determine the relative proportions of biogenic and non-biogenic CO 2 (iii) Determine the annual biogenic CO 2 2 (iv) In lieu of following the procedures in paragraphs (e)(3)(i) through (iii) of this section, the procedures of this paragraph (e)(3)(iv) may be used for the combustion of tires regardless of the percent of the annual heat input provided by tires. The calculation procedure in this paragraph (e)(3)(iv) may be used for the combustion of MSW if the combustion of MSW provides no more than 10 percent of the annual heat input to the unit or if a small, batch incinerator combusts no more than 1,000 tons per year of MSW. (A) Calculate the total annual CO 2 2 (B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO 2 (4) If Equation C-1 or Equation C-2a of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C-15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG Monitoring Plan required by § 98.3(g)(5). Where: (Fuel) p H = Average enthalpy of the boiler steam for the measurement period (Btu/lb). S = Total boiler steam production for the measurement period (lb/month or lb/year, as applicable). (HI) nb (HHV) bio (Eff) bio 2000 = Conversion factor (lb/ton). (5) For units subject to subpart D of this part and for units that use the methods in part 75 of this chapter to quantify CO 2 2 2 A e.g., A CO 2 A * EF where: CO 2 2 (HI) A EF = CO 2 2 0.001 = Conversion factor from kg to metric tons [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79140, Dec. 17, 2010; 78 FR 71950, Nov. 29, 2013; 81 FR 89251, Dec. 9, 2016; 89 FR 31900, Apr. 25, 2024; 89 FR 42220, May 14, 2024] § 98.34 Monitoring and QA/QC requirements. The CO 2 (a) For the Tier 2 Calculation Methodology: (1) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of the fuel. (2) The minimum required frequency of the HHV sampling and analysis for each type of fuel or fuel mixture (blend) is specified in this paragraph. When the specified frequency for a particular fuel or blend is based on a specified time period ( e.g., (i) For natural gas, semiannual sampling and analysis is required ( i.e., (ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the unit's storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling option is selected, sampling from a particular tank is required only on days when oil from the tank is combusted by the unit (or units) served by the tank. If you elect to sample from the storage tank upon each addition of oil to the tank, you must take at least one sample from each tank that is currently in service and whenever oil is added to the tank, for as long as the tank remains in service. You need not take any samples from a storage tank while it is out of service. Rather, take a sample when the tank is brought into service and whenever oil is added to the tank, for as long as the tank remains in service. If multiple additions of oil are made to a particular in-service tank on a given day ( e.g., e.g., etc. (A) For coal, the “type” of fuel means the rank of the coal ( i.e., e.g., etc. (B) The owner or operator shall document in the monitoring plan under § 98.3(g)(5) how the monthly sampling of each type of fuel is performed. (iii) For liquid fuels other than fuel oil, and for gaseous fuels other than natural gas (including biogas), sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart. (iv) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly. (v) For fuel blends that are received already mixed, or that are mixed on-site without measuring the exact amount of each component, as described in paragraph (a)(3)(ii) of this section, determine the HHV of the blend as follows. For blends of solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid or gaseous fuels, sampling and analysis is required at least once per calendar quarter. More frequent sampling is recommended if the composition of the blend varies significantly during the year. (3) Special considerations for blending of fuels. i.e., 2 (i) If the fuels to be blended are received separately, and if the quantity (mass or volume) of each fuel is measured before the fuels are mixed and combusted, then, for each component of the blend, calculate the CO 2 2 (ii) If the fuel is received as a blend ( i.e., e.g., 2 (A) Consider the blend to be the “fuel type,” measure its HHV at the frequency prescribed in paragraph (a)(2)(v) of this section, and determine the annual average HHV value for the blend according to § 98.33(a)(2)(ii). (B) Calculate a heat-weighted CO 2 B (C) Substitute into Equation C-2a of this subpart, the annual average HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the calculated value of (EF) B 2 where: (EF) B 2 2 (HHV) i (%Fuel) i e.g., (EF) i 2 (HHV) B (iii) Note that for the case described in paragraph (a)(3)(ii) of this section, if measured HHV values for the individual fuels in the blend or for the blend itself are not routinely received at the minimum frequency prescribed in paragraph (a)(2) of this section (or at a greater frequency), and if the unit qualifies to use Tier 1, calculate (HHV) B B B 2 B B 2 where: (HHV) B (HHV) i (%Fuel) i (iv) If the fuel blend described in paragraph (a)(3)(ii) of this section consists of a mixture of fuel(s) listed in Table C-1 of this subpart and one or more fuels not listed in Table C-1, calculate CO 2 (A) In Equation C-17, apply the term (Fuel) i i i i (B) In Equation C-1, the term “Fuel” will be equal to the total mass or volume of the blended fuel combusted during the year multiplied by the sum of the mass or volume percentages of the Table C-1 fuels in the blend. For the example in paragraph (a)(3)(iv)(A) of this section, “Fuel” = (Annual volume of the blend combusted)(0.80). (4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraph (a)(2) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations. (5) If, for a particular type of fuel, valid HHV values are obtained at less than the minimum frequency specifed in paragraph (a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of § 98.35. (6) You must use one of the following appropriate fuel sampling and analysis methods. The HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the high heat values. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (b) For the Tier 3 Calculation Methodology: (1) You must calibrate each oil and gas flow meter according to § 98.3(i) and the provisions of this paragraph (b)(1). (i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5). (A) You may use the calibration procedures specified by the flow meter manufacturer. (B) You may use an appropriate flow meter calibration method published by a consensus-based standards organization, if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (C) You may use an industry-accepted practice. (ii) In addition to the initial calibration required by § 98.3(i), recalibrate each fuel flow meter (except as otherwise provided in paragraph (b)(1)(iii) of this section) according to one of the following. You may recalibrate annually, at the minimum frequency specified by the manufacturer, or at the interval specified by industry standard practice. (iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph and from the Monitoring Plan and recordkeeping requirements of §§ 98.3(g)(5)(i)(C), (g)(6), and (g)(7), provided that the fuel supplier and the 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 only used for unit startup are also exempted from the initial and ongoing calibration requirements of this paragraph. (iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ calibration of the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once every three years. (v) For the continuously-operating units and processes described in § 98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage. (vi) If a mixture of liquid or gaseous fuels is transported by a common pipe, you may either separately meter each of the fuels prior to mixing, using flow meters calibrated according to § 98.3(i), or consider the fuel mixture to be the “fuel type” and meter the mixed fuel, using a flow meter calibrated according to § 98.3(i). (2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus-based standards organization (e.g., the American Petroleum Institute). (3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in this paragraph (b)(3). (i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or by the supplier of the fuel. (ii) For each type of fuel, the minimum required frequency for collecting and analyzing samples for carbon content and (if applicable) molecular weight is specified in this paragraph. When the sampling frequency is based on a specified time period ( e.g., (A) For natural gas, semiannual sampling and analysis is required ( i.e., (B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling option is selected, sampling from a particular tank is required only on days when oil from the tank is combusted by the unit (or units) served by the tank. If you elect to sample from the storage tank upon each addition of oil to the tank, you must take at least one sample from each tank that is currently in service and whenever oil is added to the tank, for as long as the tank remains in service. You need not take any samples from a storage tank while it is out of service. Rather, take a sample when the tank is brought into service and whenever oil is added to the tank, for as long as the tank remains in service. If multiple additions of oil are made to a particular in service tank on a given day ( e.g., e.g., etc. ( 1 i.e., e.g., etc. ( 2 (C) For liquid fuels other than fuel oil and for biogas, sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart. (D) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly. (E) For gaseous fuels other than natural gas and biogas ( e.g., (F) For mixtures (blends) of solid fuels, weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid fuels, and for gas mixtures consisting only of natural gas and biogas, sampling and analysis is required at least once per calendar quarter. For gas mixtures that contain gases other than natural gas (including biogas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on-line equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed. (iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations. (iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with the missing data procedures of § 98.35. (v) To calculate the CO 2 (A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to each component of the blend, if the mass or volume, the carbon content, and (if applicable), the molecular weight of each component are accurately measured prior to blending; or (B) Consider the blend to be the “fuel type.” Then, at the frequency specified in paragraph (b)(3)(ii)(F) of this section, measure the carbon content and, if applicable, the molecular weight of the blend and calculate the annual average value of each parameter in the manner described in § 98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel combusted during the reporting year. Substitute these measured values into Equation C-3, C-4, or C-5 of this subpart (as applicable). (4) You must use one of the following appropriate fuel sampling and analysis methods. The results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the carbon content and molecular weight (for gaseous fuel) of the fuel. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (c) For the Tier 4 Calculation Methodology, the CO 2 (1) For initial certification, you may use any one of the following three procedures in this paragraph. (i) §§ 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this chapter and appendix A to part 75 of this chapter. (ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Specification 3 in appendix B to part 60 of this chapter (for the CO 2 (iii) The provisions of an applicable State continuous monitoring program. (2) If an O 2 2 2 (3) For ongoing quality assurance, follow the applicable procedures in either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program. If appendix F to part 60 of this chapter is selected for on-going quality assurance, perform daily calibration drift assessments for both the CO 2 2 2 2 (4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required by appendix F to part 60 of this chapter need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance. (5) If, for any source operating hour, quality assured data are not obtained with a CO 2 2 (6) For applications where CO 2 2 e.g., 2 2 2 2 (7) Hourly average data from the CEMS shall be validated in a manner consistent with one of the following: §§ 60.13(h)(2)(i) through (h)(2)(vi) of this chapter; § 75.10(d)(1) of this chapter; or the hourly data validation requirements of an applicable State CEM regulation. (d) Except as otherwise provided in § 98.33(e)(3)(iv), when municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit, determine the biogenic portion of the CO 2 e.g., 2 e.g., 2 (e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels that have a biomass component, e.g., 2 (f) The records required under § 98.3(g)(2)(i) shall include an explanation of how the following parameters are determined from company records (or, if applicable, from the best available information): (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies are used, including cases where § 98.36(c)(4) applies. (2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology is used. (3) Fossil fuel consumption when § 98.33(e)(2) applies to a unit that uses CEMS to quantify CO 2 (4) Sorbent usage, when § 98.33(d) applies. (5) Quantity of steam generated by a unit when § 98.33(a)(2)(iii) applies. (6) Biogenic fuel consumption and high heating value, as applicable, under §§ 98.33(e)(5) and (e)(6). (7) Fuel usage for CH 4 2 (8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels under § 98.33(e)(1)(iii). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79146, Dec. 17, 2010; 81 FR 89251, Dec. 9, 2016; 89 FR 31902, Apr. 25, 2024] § 98.35 Procedures for estimating missing data. Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations. (a) For all units subject to the requirements of the Acid Rain Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data year-round in accordance with part 75 of this chapter, the missing data substitution procedures in part 75 of this chapter shall be followed for CO 2 (b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies, perform missing data substitution as follows for each parameter: (1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value has not been obtained by the time that the GHG emissions report is due, you may use the “before” value for missing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). 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 missing records of CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79150, Dec. 17, 2010] § 98.36 Data reporting requirements. (a) In addition to the facility-level information required under § 98.3, the annual GHG emissions report shall contain the unit-level or process-level data specified in paragraphs (b) through (f) of this section, as applicable, for each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) except as otherwise provided in this paragraph (a). For the data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, the owner or operator of a stationary fuel combustion source that does not meet the criteria specified in paragraph (f) of this section may elect either to report the data specified in this sentence in the annual report or to use verification software according to § 98.5(b) in lieu of reporting these data. If you elect to use this verification software, you must use the verification software according to § 98.5(b) for all of these data that apply to the stationary fuel combustion source. (b) Units that use the four tiers. 2 (1) The unit ID number. (2) A code representing the type of unit. (3) Maximum rated heat input capacity of the unit, in mmBtu/hr. (4) Each type of fuel combusted in the unit during the report year. (5) The methodology ( i.e., 2 i.e., (6) The methodology start date, for each fuel type. (7) The methodology end date, for each fuel type. (8) For a unit that uses Tiers 1, 2, or 3: (i) The annual CO 2 2 4 2 2 (ii) Metric tons of biogenic CO 2 (9) For a unit that uses Tier 4: (i) If the total annual CO 2 2 i.e., 2 2 2 2 2 (ii) Report the total annual CO 2 2 2 2 2 (iii) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year. (iv) The annual CH 4 2 2 (10) Annual CO 2 (11) If applicable, the plant code (as defined in § 98.6). (12) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH 4 (i) Type of equipment ( i.e. (ii) Method by which the CH 4 (iii) Value of the CH 4 (c) Reporting alternatives for units using the four Tiers. (1) Aggregation of units. (i) Group ID number, beginning with the prefix “GP”. (ii) [Reserved] (iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr). (iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr). (v) Each type of fuel combusted in the group of units during the reporting year. (vi) Annual CO 2 4 2 2 2 (vii) The methodology ( i.e., 2 i.e., (viii) The methodology start date, for each fuel type. (ix) The methodology end date, for each fuel type. (x) The calculated CO 2 (xi) If applicable, the plant code (as defined in § 98.6). (xii) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH 4 i.e. 4 i.e. 4 (2) Monitored common stack or duct configurations. 2 (i) Common stack or duct identification number, beginning with the prefix “CS”. (ii) Number of units sharing the common stack or duct. Report “1” when the flue gas flowing through the common stack or duct includes combustion products and/or process off-gases, and all of the effluent comes from a single unit ( e.g., (iii) Combined maximum rated heat input capacity of the units sharing the common stack or duct (mmBtu/hr). This data element is required only when all of the units sharing the common stack are stationary fuel combustion units. (iv) Each type of fuel combusted in the units during the year. (v) The methodology (tier) used to calculate the CO 2 i.e., (vi) The methodology start date. (vii) The methodology end date. (viii) Total annual CO 2 2 i.e., 2 2 2 2 (ix) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the units sharing the common stack or duct during the report year. (x) For each type of fuel listed in Table C-2 of this subpart that was combusted during the report year in the units sharing the common stack or duct during the report year, the annual CH 4 2 2 (xi) If applicable, the plant code (as defined in § 98.6). (3) Common pipe configurations. 2 (i) Common pipe identification number, beginning with the prefix “CP”. (ii) Cumulative maximum rated heat input capacity of the units served by the common pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units served by the common pipe, excluding units less than 10 (mmBtu/hr). (iii) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr). (iv) The fuels combusted in the units during the reporting year. (v) The methodology used to calculate the CO 2 (vi) If any of the units burns biomass, the annual CO 2 (vii) Annual CO 2 4 2 2 (viii) Methodology start date. (ix) Methodology end date. (x) If applicable, the plant code (as defined in § 98.6). (xi) For natural gas-fired reciprocating internal combustion engines or gas turbines at facilities subject to subpart W of this part, which must use a CH 4 i.e. 4 i.e. 4 (4) The following alternative reporting option applies to facilities at which a common liquid or gaseous fuel supply is shared between one or more large combustion units, such as boilers or combustion turbines (including units subject to subpart D of this part and other units subject to part 75 of this chapter) and small combustion sources, including, but not limited to, space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by attributing all of the GHG emissions from combustion of the shared fuel to the large combustion unit(s), provided that: (i) The total quantity of the fuel combusted during the report year in the units sharing the fuel supply is measured, either at the “gate” to the facility or at a point inside the facility, using a fuel flow meter, billing meter, or tank drop measurements (as applicable); (ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is combusted in the large combustion unit(s), and the remainder is combusted in the small combustion sources. Company records may be used to determine the percentage distribution of the shared fuel to the large and small units; and (iii) The use of this reporting option is documented in the Monitoring Plan required under § 98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the method used to demonstrate that this alternative reporting option applies. For the small combustion sources, a description of the types of units and the approximate number of units is sufficient. (d) Units subject to part 75 of this chapter. (i) Unit or stack identification numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations ( e.g., etc. (ii) Annual CO 2 2 (iii) Annual CH 4 2 2 (iv) The total heat input from each fuel listed in Table C-2 that was combusted during the year (except as otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in mmBtu. (v) Identification of the Part 75 methodology used to determine the CO 2 (vi) Methodology start date. (vii) Methodology end date. (viii) Acid Rain Program indicator. (ix) Annual CO 2 2 (x) If applicable, the plant code (as defined in § 98.6). (2) For units that use the alternative CO 2 (i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations ( e.g., etc. (ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round according to appendix D to part 75 of this chapter or § 75.19 of this chapter: (A) Each type of fuel combusted in the unit during the reporting year. (B) The methodology used to calculate the CO 2 (C) Methodology start date. (D) Methodology end date. (E) A code or flag to indicate whether heat input is calculated according to appendix D to part 75 of this chapter or § 75.19 of this chapter. (F) Annual CO 2 2 (G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu. (H) Annual CH 4 2 2 (I) Annual CO 2 2 (J) If applicable, the plant code (as defined in § 98.6). (iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round according to part 75 of this chapter: (A) Each type of fuel combusted during the reporting year. (B) Methodology used to calculate the CO 2 (C) Methodology start date. (D) Methodology end date. (E) A code or flag to indicate that the heat input data is derived from CEMS measurements. (F) The total annual CO 2 2 (G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu. (H) Annual CH 4 2 2 (I) Annual CO 2 2 (J) If applicable, the plant code (as defined in § 98.6). (e) Verification data. (1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions: (i) Are subject to the Acid Rain Program. (ii) Use the alternative methods for units with continuous monitoring systems provided in § 98.33(a)(5). (iii) Are not in the Acid Rain Program, but are required to monitor and report CO 2 (2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in § 98.33(a) to quantify CO 2 (i) For the Tier 1 Calculation Methodology, report: (A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural gas. (B) If applicable, the moisture content used to calculate the wood and wood residuals wet basis HHV for use in Equations C-1 and C-8 of this subpart, in percent. (ii) For the Tier 2 Calculation Methodology, report: (A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot). (C) The annual average, and, where applicable, monthly high heat values used in the CO 2 (D) If Equation C-2c of this subpart is used to calculate CO 2 i.e., (E) For each HHV used in the CO 2 (iii) For the Tier 2 Calculation Methodology, keep records of the methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for HHV are received. (iv) For the Tier 3 Calculation Methodology, report: (A) The quantity of each type of fuel combusted in the unit or group of units (as applicable) during each month of the reporting year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels. (B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot). (C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). For each calendar month of the reporting year in which carbon content and, if applicable, molecular weight determination is required, report a value of each parameter. If multiple values of a parameter are obtained in a given month, report the arithmetic average value for the month. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole. (D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type. (E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual GHG emissions calculations. (F) The annual average HHV, when measured HHV data, rather than a default HHV from Table C-1 of this subpart, are used to calculate CH 4 2 (G) The value of the molar volume constant (MVC) used in Equation C-5 (if applicable). (v) For the Tier 3 Calculation Methodology, keep records of the following: (A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters. (B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop measurements (if applicable). (C) The methods used to determine the carbon content and (if applicable) the molecular weight of each type of fuel combusted. (D) The methods used to calibrate the fuel flow meters). (E) The date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for carbon content and (if applicable) molecular weight are received. (vi) For the Tier 4 Calculation Methodology, report: (A) The total number of source operating hours in the reporting year. (B) The cumulative CO 2 (C) For CO 2 (vii) For the Tier 4 Calculation Methodology, keep records of: (A) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used. (B) The dates and results of the initial certification tests of the CEMS. (C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs). (viii) If CO 2 (A) The total amount of sorbent used during the report year, in short tons. (B) The molecular weight of the sorbent. (C) The ratio (“R”) in Equation C-11 of this subpart. (ix) For units that combust both fossil fuel and biomass, when biogenic CO 2 (A) The annual volume of CO 2 i.e. total (B) The annual volume of CO 2 i.e. ff 2 (C) The annual volume of CO 2 i.e. bio (D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in scf CO 2 (E) The annual average HHV value used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate. (F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate. (G) Annual biogenic CO 2 (x) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used to determine the biogenic portion of the annual CO 2 (A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO 2 (B) The annual biogenic CO 2 (xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine the biogenic portion of the annual CO 2 e.g., 2 (3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following: (i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO 2 (ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO 2 (iii) An explanation of how sorbent usage is quantified. (iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO 2 (v) An explanation of how company records are used to measure steam production, when it is used to calculate CO 2 (4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section. (f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) subject to reporting under paragraph (b) or (c) of this section must indicate if both of the following two conditions are met: (1) The stationary fuel combustion source contains at least one combustion unit connected to a fuel-fired electric generator owned or operated by an entity that is subject to regulation of customer billing rates by the public utility commission (excluding generators that are connected to combustion units that are subject to subpart D of this part). (2) The stationary fuel combustion source is located at a facility for which the sum of the nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is greater than or equal to 1 megawatt electric output. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79151, Dec. 17, 2010; 78 FR 71950, Nov. 29, 2013; 79 FR 63782, Oct. 24, 2014; 81 FR 89251, Dec. 9, 2016; 89 FR 31902, Apr. 25, 2024; 89 FR 42220, May 14, 2024] § 98.37 Records that must be retained. In addition to the requirements of § 98.3(g), you must retain: (a) The applicable records specified in §§ 98.34(f), 98.35(b), and 98.36(e). (b) The applicable verification software records as identified in this paragraph (b). For each stationary fuel combustion source that elects to use the verification software specified in § 98.5(b) rather than report data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (C), and (D), (e)(2)(iv)(A), (C), and (F), and (e)(2)(ix)(D) through (F) of this section, you must keep a record of the file generated by the verification software for the applicable data specified in paragraphs (b)(1) through (37) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (37) of this section. (1) Mass of each solid fuel combusted (tons/year) (equation C-1 to § 98.33). (2) Volume of each liquid fuel combusted (gallons/year) (equation C-1 to § 98.33). (3) Volume of each gaseous fuel combusted (scf/year) (equation C-1 to § 98.33). (4) Annual natural gas usage (therms/year) (equation C-1a to § 98.33). (5) Annual natural gas usage (mmBtu/year) (equation C-1b to § 98.33). (6) Mass of each solid fuel combusted (tons/year) (equation C-2a to § 98.33). (7) Volume of each liquid fuel combusted (gallons/year) (equation C-2a to § 98.33). (8) Volume of each gaseous fuel combusted (scf/year) (equation C-2a to § 98.33). (9) Measured high heat value of each solid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per ton) (equation C-2b to § 98.33). Annual average HHV of each solid fuel (mmBtu per ton) (equation C-2a to § 98.33). (10) Measured high heat value of each liquid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per gallons) (equation C-2b to § 98.33). Annual average HHV of each liquid fuel (mmBtu per gallons) (equation C-2a to § 98.33). (11) Measured high heat value of each gaseous fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per scf) (equation C-2b to § 98.33). Annual average HHV of each gaseous fuel (mmBtu per scf) (equation C-2a to § 98.33). (12) Mass of each solid fuel combusted during month (tons) (equation C-2b to § 98.33). (13) Volume of each liquid fuel combusted during month (gallons) (equation C-2b to § 98.33). (14) Volume of each gaseous fuel combusted during month (scf) (equation C-2b, equation C-5A, equation C-5B to § 98.33). (15) Total mass of steam generated by municipal solid waste or each solid fuel combustion during the reporting year (pounds steam) (equation C-2c to § 98.33). (16) Ratio of the boiler's maximum rated heat input capacity to its design rated steam output capacity (MMBtu/pounds steam) (equation C-2c to § 98.33). (17) Annual mass of each solid fuel combusted (short tons/year) (equation C-3 to § 98.33). (18) Annual average carbon content of each solid fuel (percent by weight, expressed as a decimal fraction) (equation C-3 to § 98.33). Where applicable, monthly carbon content of each solid fuel (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (percent by weight, expressed as a decimal fraction) (equation C-2b to § 98.33—see the definition of “CC” in equation C-3 to § 98.33). (19) Annual volume of each liquid fuel combusted (gallons/year) (equation C-4 to § 98.33). (20) Annual average carbon content of each liquid fuel (kg C per gallon of fuel) (equation C-4 to § 98.33). Where applicable, monthly carbon content of each liquid fuel (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg C per gallon of fuel) (equation C-2b to § 98.33—see the definition of “CC” in equation C-3 to § 98.33). (21) Annual volume of each gaseous fuel combusted (scf/year) (equation C-5 to § 98.33). (22) Annual average carbon content of each gaseous fuel (kg C per kg of fuel) (equation C-5 to § 98.33). Where applicable, monthly carbon content of each gaseous (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg C per kg of fuel) (equation C-5A to § 98.33). (23) Annual average molecular weight of each gaseous fuel (kg/kg-mole) (equation C-5 to § 98.33). Where applicable, monthly molecular weight of each gaseous (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (kg/kg-mole) (equation C-5B to § 98.33). (24) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (equation C-5 to § 98.33). (25) Identify for each fuel if you will use the default high heat value from table C-1 to this subpart, or actual high heat value data (equation C-8 to § 98.33). (26) High heat value of each solid fuel (mmBtu/tons) (equation C-8 to § 98.33). (27) High heat value of each liquid fuel (mmBtu/gallon) (equation C-8 to § 98.33). (28) High heat value of each gaseous fuel (mmBtu/scf) (equation C-8 to § 98.33). (29) Cumulative annual heat input from combustion of each fuel (mmBtu) (equation C-10 to § 98.33). (30) Total quantity of each solid fossil fuel combusted in the reporting year, as defined in § 98.6 (pounds) (equation C-13 to § 98.33). (31) Total quantity of each liquid fossil fuel combusted in the reporting year, as defined in § 98.6 (gallons) (equation C-13 to § 98.33). (32) Total quantity of each gaseous fossil fuel combusted in the reporting year, as defined in § 98.6 (scf) (equation C-13 to § 98.33). (33) High heat value of the each solid fossil fuel (Btu/lb) (equation C-13 to § 98.33). (34) High heat value of the each liquid fossil fuel (Btu/gallons) (equation C-13 to § 98.33). (35) High heat value of the each gaseous fossil fuel (Btu/scf) (equation C-13 to § 98.33). (36) Fuel-specific carbon based F-factor per fuel (scf CO 2 (37) Moisture content used to calculate the wood and wood residuals wet basis HHV (percent), if applicable (equations C-1 and C-8 to § 98.33). [79 FR 63783, Oct. 24, 2014, as amended at 81 FR 89252, Dec. 9, 2016; 89 FR 31903, Apr. 25, 2024] § 98.38 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table C-1 to Subpart C of Part 98—Default CO 2 Default CO 2 Fuel type Default high heat value Default CO 2 Coal and coke mmBtu/short ton kg CO 2 Anthracite 25.09 103.69 Bituminous 24.93 93.28 Subbituminous 17.25 97.17 Lignite 14.21 97.72 Coal Coke 24.80 113.67 Mixed (Commercial sector) 21.39 94.27 Mixed (Industrial coking) 26.28 93.90 Mixed (Industrial sector) 22.35 94.67 Mixed (Electric Power sector) 19.73 95.52 Natural gas mmBtu/scf kg CO 2 (Weighted U.S. Average) 1.026 × 10 −3 53.06 Petroleum products—liquid mmBtu/gallon kg CO 2 Distillate Fuel Oil No. 1 0.139 73.25 Distillate Fuel Oil No. 2 0.138 73.96 Distillate Fuel Oil No. 4 0.146 75.04 Residual Fuel Oil No. 5 0.140 72.93 Residual Fuel Oil No. 6 0.150 75.10 Used Oil 0.138 74.00 Kerosene 0.135 75.20 Liquefied petroleum gases (LPG) 1 0.092 61.71 Propane 1 0.091 62.87 Propylene 2 0.091 67.77 Ethane 1 0.068 59.60 Ethanol 0.084 68.44 Ethylene 2 0.058 65.96 Isobutane 1 0.099 64.94 Isobutylene 1 0.103 68.86 Butane 1 0.103 64.77 Butylene 1 0.105 68.72 Naphtha (<401 deg F) 0.125 68.02 Natural Gasoline 0.110 66.88 Other Oil (>401 deg F) 0.139 76.22 Pentanes Plus 0.110 70.02 Petrochemical Feedstocks 0.125 71.02 Special Naphtha 0.125 72.34 Unfinished Oils 0.139 74.54 Heavy Gas Oils 0.148 74.92 Lubricants 0.144 74.27 Motor Gasoline 0.125 70.22 Aviation Gasoline 0.120 69.25 Kerosene-Type Jet Fuel 0.135 72.22 Asphalt and Road Oil 0.158 75.36 Crude Oil 0.138 74.54 Petroleum products—solid mmBtu/short ton kg CO 2 Petroleum Coke 30.00 102.41. Petroleum products—gaseous mmBtu/scf kg CO 2 Propane Gas 2.516 × 10 −3 61.46. Other fuels—solid mmBtu/short ton kg CO 2 Municipal Solid Waste 9.95 3 90.7 Tires 28.00 85.97 Plastics 38.00 75.00 Other fuels—gaseous mmBtu/scf kg CO 2 Blast Furnace Gas 0.092 × 10 −3 274.32 Coke Oven Gas 0.599 × 10 −3 46.85 Fuel Gas 4 1.388 × 10 −3 59.00 Biomass fuels—solid mmBtu/short ton kg CO 2 Wood and Wood Residuals (dry basis) 5 17.48 93.80 Agricultural Byproducts 8.25 118.17 Peat 8.00 111.84 Solid Byproducts 10.39 105.51 Biomass fuels—gaseous mmBtu/scf kg CO 2 Landfill Gas 0.485 × 10 −3 52.07 Other Biomass Gases 0.655 × 10 −3 52.07 Biomass Fuels—Liquid mmBtu/gallon kg CO 2 Ethanol 0.084 68.44 Biodiesel (100%) 0.128 73.84 Rendered Animal Fat 0.125 71.06 Vegetable Oil 0.120 81.55 1 2 3 4 2 5 w d w d [78 FR 71950, Nov. 29, 2013, as amended at 81 FR 89252, Dec. 9, 2016] Table C-2 to Subpart C of Part 98—Default CH 4 2 Fuel type Default CH 4 4 Default N 2 2 Coal and Coke (All fuel types in Table C-1) 1.1 × 10 −02 1.6 × 10 −03 Natural Gas 1 1.0 × 10− 03 1.0 × 10− 04 Petroleum Products (All fuel types in Table C-1) 3.0 × 10 −03 6.0 × 10 −04 Fuel Gas 3.0 × 10 −03 6.0 × 10 −04 Other Fuels—Solid 3.2 × 10 −02 4.2 × 10 −03 Blast Furnace Gas 2.2 × 10 −05 1.0 × 10 −04 Coke Oven Gas 4.8 × 10 −04 1.0 × 10 −04 Biomass Fuels—Solid (All fuel types in Table C-1, except wood and wood residuals) 3.2 × 10 −02 4.2 × 10 −03 Wood and wood residuals 7.2 × 10 −03 3.6 × 10 −03 Biomass Fuels—Gaseous (All fuel types in Table C-1) 3.2 × 10 −03 6.3 × 10 −04 Biomass Fuels—Liquid (All fuel types in Table C-1) 1.1 × 10 −03 1.1 × 10 −04 Note: Those employing this table are assumed to fall under the IPCC definitions of the “Energy Industry” or “Manufacturing Industries and Construction”. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC “Energy Industry” category may employ a value of 1g of CH 4 1 4 4 [78 FR 71952, Nov. 29, 2013, as amended at 81 FR 89252, Dec. 9, 2016; 89 FR 42220, May 14, 2024] Subpart D—Electricity Generation § 98.40 Definition of the source category. (a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO 2 (b) This source category does not include portable equipment, emergency equipment, or emergency generators, as defined in § 98.6. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010] § 98.41 Reporting threshold. You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of § 98.2(a)(1). § 98.42 GHGs to report. (a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA CO 2 2 2 4 (b) For each electricity generating unit that is not subject to the Acid Rain Program or otherwise required to monitor and report to EPA CO 2 2 4 2 (c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 § 98.43 Calculating GHG emissions. (a) Except as provided in paragraph (b) of this section, continue to monitor and report CO 2 2 4 2 (1) Convert the cumulative annual CO 2 (2) Calculate and report annual CH 4 2 (b) Calculate and report biogenic CO 2 2 2 2 2 2 [75 FR 79155, Dec. 17, 2010] § 98.44 Monitoring and QA/QC requirements. Follow the applicable quality assurance procedures for CO 2 § 98.45 Procedures for estimating missing data. Follow the applicable missing data substitution procedures in 40 CFR part 75 for CO 2 § 98.46 Data reporting requirements. The annual report shall comply with the data reporting requirements specified in § 98.36(d)(1). [75 FR 79155, Dec. 17, 2010] § 98.47 Records that must be retained. You shall comply with the recordkeeping requirements of §§ 98.3(g) and 98.37. Records retained under § 75.57(h) of this chapter for missing data events satisfy the recordkeeping requirements of § 98.3(g)(4) for those same events. [75 FR 79155, Dec. 17, 2010] § 98.48 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart E—Adipic Acid Production § 98.50 Definition of source category. The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid. § 98.51 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.52 GHGs to report. (a) You must report N 2 (b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 § 98.53 Calculating GHG emissions. (a) You must determine annual N 2 (1) Use a site-specific emission factor and production data according to paragraphs (b) through (i) of this section. (2) Request Administrator approval for an alternative method of determining N 2 (i) If you received Administrator approval for an alternative method of determining N 2 (ii) You must notify the EPA of your use of a previously approved alternative method in your annual report. (iii) Otherwise, you must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year. (iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N 2 (b) You must conduct an annual performance test according to paragraphs (b)(1) through (3) of this section. (1) You must conduct the test on the vent stream from the nitric acid oxidation step of the process, referred to as the test point, according to the methods specified in § 98.54(b) through (f). If multiple adipic acid production units exhaust to a common abatement technology and/or emission point, 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 multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple adipic acid production units. (2) You must conduct the performance test under normal process operating conditions. (3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in tons per hour. (c) Using the results of the performance test in paragraph (b) of this section, you must calculate an emission factor for each adipic acid unit according to Equation E-1 of this section: where: EF N 2 O,z 2 2 C N 2 O 2 2 1.14 × 10 −7 2 Q = Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr). P = Production rate per test run during the performance test (tons adipic acid produced/hr). n = Number of test runs. (d) If the adipic acid production unit exhausts to any N 2 (1) Use the manufacturer's specified destruction efficiency. (2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge was used to determine the destruction efficiency. (3) Calculate the destruction efficiency by conducting an additional performance test on the vent stream following the N 2 (e) If the adipic acid production unit exhausts to any N 2 2 2 (f) You must determine the annual amount of adipic acid produced according to § 98.54(f). (g) You must calculate N 2 (1) If one N 2 where: E a,z 2 EF N 2 Oz 2 2 P z DF = Destruction efficiency of N 2 2 AF = Abatement utilization factor of N 2 2205 = Conversion factor (lb/metric ton). (2) If multiple N 2 where: E b,z 2 EF N 2 O,z 2 2 P z DF 1 2 2 AF 1 2 DF 2 2 2 AF 2 2 DF N 2 2 AF N 2 2205 = Conversion factor (lb/metric ton). N = Number of different N 2 (3) If multiple N 2 where: E c,z 2 EF N 2 O,z 2 2 P z DF N 2 2 AF N 2 FC N 2 2205 = Conversion factor (lb/metric ton). N = Number of different N 2 (4) If no N 2 where: E d,z 2 EF N 2 O 2 2 P Z 2205 = Conversion factor (lb/metric ton). (h) You must determine the emissions for the facility by summing the unit level emissions according to Equation E-4 of this section. where: E a,z 2 E b,z 2 E c,z 2 E d,z 2 M = Total number of adipic acid production units. (i) You must determine the amount of process N 2 2 [75 FR 66458, Oct. 28, 2010, as amended at 78 FR 71952, Nov. 29, 2013; 81 FR 89252, Dec. 9, 2016] § 98.54 Monitoring and QA/QC requirements. (a) You must conduct a new performance test and calculate a new emissions factor for each adipic acid production unit according to the frequency specified in paragraphs (a)(1) through (3) of this section. (1) Conduct the performance test annually. The test must be conducted at a point during production that is representative of the average emissions rate from your process. You must document the methods used to determine the representative point. (2) Conduct the performance test when your adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or by installing abatement equipment. (3) If you requested Administrator approval for an alternative method of determining N 2 (b) You must measure the N 2 (1) EPA Method 320, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A; (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see (3) An equivalent method, with Administrator approval. (c) You must determine the adipic acid production rate during the performance test according to paragraph (c)(1) or (c)(2) of this section. (1) Direct measurement (such as using flow meters or weigh scales). (2) Existing plant procedures used for accounting purposes. (d) You must determine the volumetric flow rate during the performance test in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emissions factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section: (1) Analysis of samples, determination of emissions, and raw data. (2) All information and data used to derive the emissions factor. (3) The production rate(s) during the performance test and how each production rate was determined. (e) You must determine the monthly amount of adipic acid produced. You must also determine the monthly amount of adipic acid produced during which N 2 (f) You must determine the annual amount of adipic acid produced. You must also determine the annual amount of adipic acid produced during which N 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66460, Oct. 28, 2010; 78 FR 71953, Nov. 29, 2013] § 98.55 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of monthly adipic acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records). (b) For missing values related to the performance test, including emission factors, production rate, and N 2 § 98.56 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (n) of this section at the facility level. (a) Annual process N 2 (b)-(c) [Reserved] (d) Annual process N 2 (e) Number of abatement technologies (if applicable). (f) Types of abatement technologies used and date of installation for each (if applicable). (g) Abatement technology destruction efficiency for each abatement technology (percent destruction). (h) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating). (i) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production (months). (j) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.53(a)(1), each annual report must also contain the information specified in paragraphs (j)(1) through (7) of this section for each adipic acid production unit. (1) [Reserved] (2) Test method used for performance test. (3) [Reserved] (4) N 2 2 (5) Volumetric flow rate per test run during performance test (dscf/hr). (6) Number of test runs. (7) Number of times in the reporting year that a performance test had to be repeated (number). (k) If you requested Administrator approval for an alternative method of determining N 2 (1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date. (l) Fraction control factor for each abatement technology (percent of total emissions from the production unit that are sent to the abatement technology) if equation E-3c is used. (m) If only cyclohexane is oxidized to produce adipic acid and the quantity is known, report the information specified in paragraph (m)(1) of this section. If materials other than cyclohexane are oxidized to produce adipic acid, report the information specified in paragraph (m)(2) of this section. (1) Annual quantity of cyclohexane (tons) used to produce adipic acid. (2) Annual quantity of cyclohexanone and cyclohexanol mixture (tons) used to produce adipic acid. (n) Annual percent N 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66460, Oct. 28, 2010; 79 FR 63784, Oct. 24, 2014; 81 FR 89253, Dec. 9, 2016] § 98.57 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (i) of this section at the facility level: (a) Annual adipic acid production capacity (tons). (b) Records of significant changes to process. (c) Number of facility and unit operating hours in calendar year. (d) Documentation of how accounting procedures were used to estimate production rate. (e) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency. (f) Performance test reports. (g) Measurements, records and calculations used to determine reported parameters. (h) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (i) Verification software records. (1) Annual adipic acid production from each adipic acid production unit (tons) (Equations E-2, E-3a, E-3b, E-3c, and E-3d of § 98.53). (2) Production rate per test run during the performance test for each production unit test run (tons adipic acid produced/hr) (Equation E-1 of § 98.53). (3) Annual adipic acid production per N 2 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 79 FR 63784, Oct. 24, 2014] § 98.58 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart F—Aluminum Production § 98.60 Definition of the source category. (a) A primary aluminum production facility manufactures primary aluminum using the Hall-Héroult manufacturing process. The primary aluminum manufacturing process comprises the following operations: (1) Electrolysis in prebake and Søderberg cells. (2) Anode baking for prebake cells. (b) This source category does not include experimental cells or research and development process units. § 98.61 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.62 GHGs to report. You must report: (a) Perfluoromethane (CF 4 2 6 (b) CO 2 (c) CO 2 (d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 2 4 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010] § 98.63 Calculating GHG emissions. (a) The annual value of each PFC compound (CF 4 2 6 Where: E PFC E m (b) Use Equation F-2 of this section to estimate CF 4 4 2 6 Where: E CF4 4 4 S CF4 4 AEM = The anode effect minutes per cell-day (AE-Mins/cell-day). MP = Metal production (metric tons Al), where AEM and MP are calculated monthly. Where: E CF4 4 4 EF CF4 4 MP = Metal production (metric tons Al), where MP is calculated monthly. Where: E C2F6 2 6 2 6 E CF4 4 4 F C2F6/CF4 2 6 4 2 6 4 0.001 = Conversion factor from kg to metric tons, where E CF4 (c) You must calculate and report the annual process CO 2 (d) Calculate and report under this subpart the process CO 2 (e) Use the following procedures to calculate CO 2 (1) For Prebake cells: you must calculate CO 2 Where: E CO2 2 2 NAC = Net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al). MP = Annual metal production (metric tons Al). S a Ash a 44/12 = Ratio of molecular weights, CO 2 (2) For Søderberg cells you must calculate CO 2 Where: E CO2 2 2 PC = Annual paste consumption (metric ton/metric ton Al). MP = Annual metal production (metric ton Al). CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton Al). BC = Binder content of paste (percent weight). S p Ash p H p = S c = Ash c = CD = Carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al). 44/12 = Ratio of molecular weights, CO 2 (f) Use the following procedures to calculate CO 2 (1) Use Equation F-7 of this section to calculate emissions from pitch volatiles combustion. Where: E CO2PV 2 2 GA = Initial weight of green anodes (metric tons). H w BA = Annual baked anode production (metric tons). WT = Annual waste tar collected (metric tons). 44/12 = Ratio of molecular weights, CO 2 (2) Use Equation F-8 of this section to calculate emissions from bake furnace packing material. Where: E CO2PC 2 2 PCC = Annual packing coke consumption (metric tons/metric ton baked anode). BA = Annual baked anode production (metric tons). S pc Ash pc 44/12 = Ratio of molecular weights, CO 2 (g) If process CO 2 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010] § 98.64 Monitoring and QA/QC requirements. (a) Effective December 31, 2010 for smelters with no prior measurement or effective December 31, 2012, for facilities with historic measurements, the smelter-specific slope coefficients, overvoltage emission factors, and weight fractions used in Equations F-2, F-3, and F-4 of this subpart must be measured in accordance with the recommendations of the EPA/IAI Protocol for Measurement of Tetrafluoromethane (CF 4 2 6 (b) The minimum frequency of the measurement and analysis is annually except as follows: (1) Monthly for anode effect minutes per cell day (or anode effect overvoltage and current efficiency). (2) Monthly for aluminum production. (3) Smelter-specific slope coefficients, overvoltage emission factors, and weight fractions according to paragraph (a) of this section. (c) Sources may use either smelter-specific values from annual measurements of parameters needed to complete the equations in § 98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values shown in Table F-2 of this subpart. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79155, Dec. 17, 2010] § 98.65 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements: (a) Where anode or paste consumption data are missing, CO 2 Where: ECO 2 2 2 EF p 2 MP p EF s 2 MP s (b) For other parameters, use the average of the two most recent data points after the missing data. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 81 FR 89253, Dec. 9, 2016] § 98.66 Data reporting requirements. In addition to the information required by § 98.3(c), you must report the following information at the facility level: (a) [Reserved] (b) Type of smelter technology used. (c) The following PFC-specific information on an annual basis: (1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all Søderberg electrolysis cells combined. (2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%)). (3) Smelter-specific slope coefficients (or overvoltage emission factors) and the last date when the smelter-specific slope coefficients (or overvoltage emission factors) were measured. (d) Method used to measure the frequency and duration of anode effects (or overvoltage). (e) The following CO 2 (1) Annual anode consumption if using the method in § 98.63(g). (2) Annual CO 2 (f) The following CO 2 (1) Annual paste consumption if using the method in § 98.63(g). (2) Annual CO 2 (g) [Reserved] (h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 79 FR 63784, Oct. 24, 2014; 81 FR 89253, Dec. 9, 2016] § 98.67 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the following records: (a) Monthly aluminum production in metric tons. (b) Type of smelter technology used. (c) The following PFC-specific information on a monthly basis: (1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and Søderberg electolysis cells. (2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF 4 (3) Smelter-specific slope coefficients and the last date when the smelter-specific-slope coefficients were measured. (d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency). (e) The following CO 2 (1) Annual anode consumption. (2) Annual CO 2 (f) The following CO 2 (1) Annual paste consumption. (2) Annual CO 2 (g) Smelter-specific inputs to the CO 2 (h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other). (i) Verification software records. (1) Slope coefficient per potline per month (kg CF 4 (2) Anode effect minutes per cell-day per potline per month (AE-Mins/cell-day) (Equation F-2). (3) Anode effect frequency per potline per month (AE/cell-day) (Equation F-2). (4) Anode effect duration per potline per month (minutes) (Equation F-2). (5) Metal production of aluminum per potline per month (metric tons) (Equation F-2). (6) Overvoltage emission factor per potline per month (kg CF4/metric ton Al) (Equation F-3 of § 98.63). (7) Metal production of aluminum per potline per month (metric tons) (Equation F-3). (8) Weight fraction of C 2 4 2 6 4 (9) Net annual prebaked anode consumption (metric tons C/metric tons Al) (Equation F-5 of § 98.63). (10) Annual metal production of aluminum (metric tons) (Equation F-5). (11) Sulfur content in baked anode (weight percent) (Equation F-5). (12) Ash content in baked anode (weight percent) (Equation F-5). (13) Annual paste consumption (metric ton/metric ton Al) (Equation F-6 of § 98.63). (14) Annual metal production of aluminum (metric tons) (Equation F-6). (15) Annual emissions of cyclohexane soluble matter (kg/metric ton Al) (Equation F-6). (16) Binder content of paste (weight percent) (Equation F-6). (17) Sulfur content of pitch (weight percent) (Equation F-6). (18) Ash content of pitch (weight percent) (Equation F-6). (19) Hydrogen content of pitch (weight percent) (Equation F-6). (20) Sulfur content in calcined coke (weight percent) (Equation F-6). (21) Ash content in calcined coke (weight percent) (Equation F-6). (22) Carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) (Equation F-6). (23) Initial weight of green anodes (metric tons) (Equation F-7 of § 98.63). (24) Annual hydrogen content in green anodes (metric tons) (Equation F-7). (25) Annual baked anode production (metric tons) (Equation F-7). (26) Annual waste tar collected (metric tons) (Equation F-7). (27) Annual packing coke consumption (metric tons/metric ton baked anode) (Equation F-8 of § 98.63). (28) Annual baked anode production (metric tons) (Equation F-8). (29) Sulfur content in packing coke (weight percent) (Equation F-8). (30) Ash content in packing coke (weight percent) (Equation F-8). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63784, Oct. 24, 2014] § 98.68 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table F-1 to Subpart F of Part 98—Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From Aluminum Production Technology CF 4 4 CF 4 4 Weight fraction C 2 6 4 2 6 4 Center Worked Prebake (CWPB) 0.143 1.16 0.121 Side Worked Prebake (SWPB) 0.272 3.65 0.252 Vertical Stud Søderberg (VSS) 0.092 NA 0.053 Horizontal Stud Søderberg (HSS) 0.099 NA 0.085 [75 FR 79156, Dec. 17, 2010] Table F-2 to Subpart F of Part 98—Default Data Sources for Parameters Used for CO 2 Parameter Data source CO 2 MP: metal production (metric tons Al) Individual facility records. NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) Individual facility records. S a 2.0. Ash a 0.4. CO 2 MP: metal production (metric tons Al) Individual facility records. PC: annual paste consumption (metric ton/metric ton Al) Individual facility records. CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) HSS: 4.0. BC: binder content of paste (percent weight) Dry Paste: 24. S p 0.6. Ash p 0.2. H p 3.3. S c 1.9. Ash c 0.2. CD: carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) 0.01. CO 2 GA: initial weight of green anodes (metric tons) Individual facility records. H w 0.005 × GA. BA: annual baked anode production (metric tons) Individual facility records. WT: annual waste tar collected (metric tons) (a) 0.005 × GA. (a) Riedhammer furnaces (b) insignificant. (b) all other furnaces CO 2 PCC: annual packing coke consumption (metric tons/metric ton baked anode) 0.015. BA: annual baked anode production (metric tons) Individual facility records. S pc 2. Ash pc 2.5. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010] Subpart G—Ammonia Manufacturing § 98.70 Definition of source category. The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this section. (a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon. (b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material. § 98.71 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.72 GHGs to report. You must report: (a) CO 2 (b) CO 2 4 2 2 (c) CO 2 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 89 FR 31904, Apr. 25, 2024] § 98.73 Calculating GHG emissions. You must calculate and report the annual CO 2 (a) Calculate and report under this subpart the process CO 2 (b) Calculate and report under this subpart process CO 2 (1) Gaseous feedstock. 2 Where: CO 2,G 2 Fdstk n CC n MW = Molecular weight of the gaseous feedstock (kg/kg-mole). MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. n = Number of month. (2) Liquid feedstock. 2 Where: CO 2,L 2 Fdstk n CC n 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. n = Number of month. (3) Solid feedstock. 2 Where: CO 2,S 2 Fdstk n CC n 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. n = Number of month. (4) CO 2 process emissions. 2 Where: CO 2 2 CO 2,p 2 p = Index for feedstock type; 1 indicates gaseous feedstock; 2 indicates liquid feedstock; and 3 indicates solid feedstock. (c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 89 FR 31904, Apr. 25, 2024] § 98.74 Monitoring and QA/QC requirements. (a) You must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis. (b) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption. (c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through (c)(8) of this section, as applicable. (1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see (2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see (3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements (incorporated by reference, see (4) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see (5) 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 (6) 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 (7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see (8) ASTM D5373-08 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (d) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous feedstock volumes and flow rates (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 feedstock volumes) according to § 98.34(b)(2). (e) For quality assurance and quality control of the supplier data, on an annual basis, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section. (f) You may use company records or an engineering estimate to determine the annual ammonia production and the annual methanol production. (g) If CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79156, Dec. 17, 2010; 81 FR 89253, Dec. 9, 2016] § 98.75 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in § 98.74 cannot be followed (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For missing data on monthly carbon contents of feedstock, the substitute data value shall be the arithmetic average of the quality-assured values of that carbon content in the month preceding and the month immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon content obtained in the month after the missing data period. (b) For missing feedstock supply rates used to determine monthly feedstock consumption, you must determine the best available estimate(s) of the parameter(s), based on all available process data. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71953, Nov. 29, 2013] § 98.76 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing unit. (a) If a CEMS is used to measure CO 2 (1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock). (2) Method used for determining quantity of feedstock used. (3) Annual ammonia production (metric tons, sum of all process units reported within subpart G of this part). (b) If a CEMS is not used to measure emissions, then you must report all of the following information in this paragraph (b): (1) Annual CO 2 (2) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock). (3) Method used for determining quantity of monthly feedstock used. (4) Whether carbon content for each feedstock for month n is based on reports from the supplier or analysis of carbon content. (5) If carbon content of feedstock for month n is based on analysis, the test method used. (6) Sampling analysis results of carbon content of feedstock as determined for QA/QC of supplier data under § 98.74(e). (7) Annual average carbon content of each type of feedstock consumed. (8)-(11) [Reserved] (12) Annual urea production (metric tons) and method used to determine urea production. (13) Annual amount of CO 2 2 (14) Annual ammonia production (metric tons, sum of all process units reported within subpart G). (15) Annual quantity of methanol intentionally produced as a desired product, for each process unit (metric tons). (16) Annual quantity of excess hydrogen produced that is not consumed through the production of ammonia (metric tons). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71953, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014; 81 FR 89253, Dec. 9, 2016; 89 FR 31904, Apr. 25, 2024] § 98.77 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a) through (c) of this section for each ammonia manufacturing unit. (a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in § 98.37 for the Tier 4 Calculation Methodology. (b) If a CEMS is not used to measure process CO 2 (1) Records of all analyses and calculations conducted for reported data as listed in § 98.76(b). (2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content. (c) Verification software records. (1) Volume of each gaseous feedstock used in month (scf of feedstock) (in Equation G-1 of § 98.73). (2) Carbon content of each gaseous feedstock, for month (kg C per kg of feedstock) (in Equation G-1). (3) Molecular weight of each gaseous feedstock per ammonia manufacturing unit with gaseous feedstock (kg/kg-mole) (Equation G-1). (4) Volume of each liquid feedstock used in month (gallons of feedstock) (Equation G-2 of § 98.73). (5) Carbon content of each liquid feedstock, for month (kg C per gallon of feedstock) (Equation G-2). (6) Mass of each solid feedstock used in month (kg of feedstock) (Equation G-3 of § 98.73). (7) Carbon content of each solid feedstock, for month (kg C per kg of feedstock) (Equation G-3). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63785, Oct. 24, 2014] § 98.78 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart H—Cement Production § 98.80 Definition of the source category. The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn hazardous waste. § 98.81 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.82 GHGs to report. You must report: (a) CO 2 (b) CO 2 (c) CH 4 2 (d) CO 2 4 2 § 98.83 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) For each cement kiln that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 2 (b) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 (c) Calculate and report under this subpart the combined process and combustion CO 2 2 (d) Calculate and report process and combustion CO 2 (1) Calculate CO 2 Where: CO 2 CMF 2 CO 2 Cli,m 2 CO 2 rm,m 2 k = Total number of kilns at a cement manufacturing facility. (2) CO 2 emissions from clinker production. 2 Where: Cli, j EF Cli,j 2 CKD, i EF CKD,i 2 p = Number of months for clinker calculation, 12. r = Number of quarters for CKD calculation, 4. 2000/2205 = Conversion factor to convert tons to metric tons. (i) Kiln-Specific Clinker Emission Factor. Where: Cli CaO Cli ncCaO MR CaO 2 Cli MgO Cli ncMgO MR MgO 2 (B) Non-calcined CaO is CaO that remains in the clinker in the form of CaCO 3 3 (ii) Kiln-Specific CKD Emission Factor. Where: CKD CaO CKD ncCaO MR CaO 2 CKD MgO CKD ncMgO MR MgO 2 (B) Non-calcined CaO is CaO that remains in the CKD in the form of CaCO 3 3 (3) CO 2 emissions from raw materials from each kiln. 2 Where: rm = The amount of raw material i consumed annually from kiln m, tons/yr (dry basis) or the amount of raw kiln feed consumed annually from kiln m, tons/yr (dry basis). CO 2,rm,m 2 TOC rm M = Number of raw materials or 1 if calculating emissions based on combined raw kiln feed. 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion factor to convert tons to metric tons. (4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 89 FR 31905, Apr. 25, 2024] § 98.84 Monitoring and QA/QC requirements. (a) You must determine the weight fraction of total CaO and total MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09, Standard Test Methods for Chemical Analysis of Hydraulic Cement (incoporated by reference, see § 98.7). The monitoring must be conducted quarterly for each kiln from a CKD sample drawn either as CKD is exiting the kiln or from bulk CKD storage. (b) You must determine the weight fraction of total CaO and total MgO in clinker from each kiln using ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7). The monitoring must be conducted monthly for each kiln from a monthly clinker sample drawn from bulk clinker storage if storage is dedicated to the specific kiln, or from a monthly arithmetic average of daily clinker samples drawn from the clinker conveying systems exiting each kiln. (c) The total organic carbon content (dry basis) of raw materials must be determined annually using ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7) or a similar industry standard practice or method approved for total organic carbon determination in raw mineral materials. The analysis must be conducted either on sample material drawn from bulk raw kiln feed storage or on sample material drawn from bulk raw material storage for each category of raw material (i.e., limestone, sand, shale, iron oxide, and alumina). Facilities that opt to use the default total organic carbon factor provided in § 98.83(d)(3), are not required to monitor for TOC. (d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement of clinker using the same plant techniques used for accounting purposes, such as reconciling weigh hopper or belt weigh feeder measurements against inventory measurements. As an alternative, facilities may also determine clinker production by direct measurement of raw kiln feed and application of a kiln-specific feed-to-clinker factor. Facilities that opt to use a feed-to-clinker factor must verify the accuracy of this factor on a monthly basis. (e) The quantity of CKD not recycled to the kiln generated by each kiln must be determined quarterly using the same plant techniques used for accounting purposes, such as direct weight measurement using weigh hoppers, truck weigh scales, or belt weigh feeders. (f) The annual quantity of raw kiln feed or annual quantity of each category of raw materials consumed by the facility (e.g., limestone, sand, shale, iron oxide, and alumina) must be determined monthly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders. (g) The monthly non-calcined CaO and MgO that remains in the clinker in the form of CaCO 3 (h) The quarterly non-calcined CaO and MgO that remains in the CKD in the form of CaCO 3 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010] § 98.85 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in § 98.83 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. The owner or operator must document and keep records of the procedures used for all such estimates. (a) If the CEMS approach is used to determine combined process and combustion CO 2 (b) For CO 2 (c) For each missing value of monthly clinker production the substitute data value must be the best available estimate of the monthly clinker production based on information used for accounting purposes, or use the maximum tons per day capacity of the system and the number of days per month. (d) For each missing value of monthly raw material consumption the substitute data value must be the best available estimate of the monthly raw material consumption based on information used for accounting purposes (such as purchase records), or use the maximum tons per day raw material throughput of the kiln and the number of days per month. § 98.86 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as appropriate. (a) If a CEMS is used to measure CO 2 (1) Monthly clinker production from each kiln at the facility. (2) Annual facility cement production. (3) Number of kilns and number of operating kilns. (4) Annual arithmetic average of total CaO content of clinker at the facility, wt-fraction. (5) Annual arithmetic average of non-calcined CaO content of clinker at the facility, wt-fraction. (6) Annual arithmetic average of total MgO content of clinker at the facility, wt-fraction. (7) Annual arithmetic average of non-calcined MgO content of clinker at the facility, wt-fraction. (8) Annual facility CKD not recycled to the kiln(s), tons. (b) If a CEMS is not used to measure CO 2 (1) Kiln identification number. (2) [Reserved] (3) Annual cement production at the facility. (4) Number of kilns and number of operating kilns. (5)-(6) [Reserved] (7) Method used to determine non-calcined CaO and non-calcined MgO in clinker. (8) [Reserved] (9) Method used to determine non-calcined CaO and non-calcined MgO in CKD. (10) [Reserved] (11) Quarterly kiln-specific CKD CO 2 2 (12) [Reserved] (13) Name of raw kiln feed or raw material. (14) Number of times missing data procedures were used to determine the following information: (i) Clinker production (number of months). (ii) Carbonate contents of clinker (number of months). (iii) Non-calcined content of clinker (number of months). (iv) CKD not recycled to kiln (number of quarters). (v) Non-calcined content of CKD (number of quarters) (vi) Organic carbon contents of raw materials (number of times). (vii) Raw material consumption (number of months). (15) Method used to determine the monthly clinker production from each kiln. (16) Annual clinker production (metric tons). (17) Annual average clinker CO 2 2 (18) Annual average CKD CO 2 2 (19) Annual arithmetic average of total CaO content of clinker at the facility, wt-fraction. (20) Annual arithmetic average of non-calcined CaO content of clinker at the facility, wt-fraction. (21) Annual arithmetic average of total MgO content of clinker at the facility, wt-fraction. (22) Annual arithmetic average of non-calcined MgO content of clinker at the facility, wt-fraction. (23) Annual arithmetic average of total CaO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (24) Annual arithmetic average of non-calcined CaO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (25) Annual arithmetic average of total MgO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (26) Annual arithmetic average of non-calcined MgO content of CKD not recycled to the kiln(s) at the facility, wt-fraction. (27) Annual facility CKD not recycled to the kiln(s), tons. (28) The amount of raw kiln feed consumed annually at the facility, tons (dry basis). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 78 FR 71953, Nov. 29, 2013; 79 FR 63785, Oct. 24, 2014; 89 FR 31905, Apr. 25, 2024] § 98.87 Records that must be retained. (a) If a CEMS is used to measure CO 2 (b) If a CEMS is not used to measure CO 2 (1) Documentation of monthly calculated kiln-specific clinker CO 2 (2) Documentation of quarterly calculated kiln-specific CKD CO 2 (3) Measurements, records and calculations used to determine reported parameters. (c) Verification software records. (1) Identify per kiln per month if clinker is measured directly, or is calculated from raw feed (Equation H-2 of § 98.83 and the method in § 98.84(d)). (2) Quantity of raw kiln feed in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)). (3) Kiln-specific factor per kiln per month (ton clinker per ton raw feed) (Equation H-2 and the method in § 98.84(d)). (4) Quantity of clinker produced in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)). (5) Cement kiln dust (CKD) not recycled to the kiln in quarter from kiln (tons) (Equation H-2 and the method in § 98.84(d)). (6) Monthly total CaO content of clinker per kiln (weight fraction) (Equation H-3 of § 98.83). (7) Monthly non-calcined CaO content of clinker per kiln (weight fraction) (Equation H-3). (8) Monthly total MgO content of clinker per kiln (weight fraction) (Equation H-3). (9) Monthly non-calcined MgO content of clinker per kiln (weight fraction) (Equation H-3). (10) Quarterly total CaO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4 of § 98.83). (11) Quarterly non-calcined CaO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4). (12) Quarterly total MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4). (13) Quarterly non-calcined MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4). (14) The amount of each raw material consumed annually per kiln (tons/yr (dry basis)) (Equation H-5 of § 98.83). (15) The amount of each raw kiln feed consumed annually per kiln (tons/yr (dry basis)) (Equation H-5). (16) Organic carbon content of each raw material per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5). (17) Organic carbon content of combined raw kiln feed per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5). [75 FR 66461, Oct. 28, 2010, as amended at 79 FR 63785, Oct. 24, 2014] § 98.88 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart I—Electronics Manufacturing Source: 75 FR 74818, Dec. 1, 2010, unless otherwise noted. § 98.90 Definition of the source category. (a) The electronics manufacturing source category consists of any of the production processes listed in paragraphs (a)(1) through (a)(5) of this section that use fluorinated GHGs or N 2 (1) Any electronics production process in which the etching process uses plasma-generated fluorine atoms and other reactive fluorine-containing fragments, that chemically react with exposed thin-films (e.g., dielectric, metals) or substrate (e.g., silicon) to selectively remove portions of material. (2) Any electronics production process in which chambers used for depositing thin films are cleaned periodically using plasma-generated fluorine atoms and other reactive fluorine-containing fragments. (3) Any electronics production process in which wafers are cleaned using plasma generated fluorine atoms or other reactive fluorine-containing fragments to remove residual material from wafer surfaces, including the wafer edge. (4) Any electronics production process in which the chemical vapor deposition (CVD) process or other manufacturing processes use N 2 (5) Any electronics manufacturing production process in which fluorinated heat transfer fluids are used to cool process equipment, to control temperature during device testing, to clean substrate surfaces and other parts, and for soldering (e.g., vapor phase reflow). [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012] § 98.91 Reporting threshold. (a) You must report GHG emissions under this subpart if electronics manufacturing production processes, as defined in § 98.90, are performed at your facility and your facility meets the requirements of either § 98.2(a)(1) or (2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO 2 (1) If you manufacture semiconductors or MEMS you must calculate annual production process emissions resulting from the use of each input gas for threshold applicability purposes using either the default emission factors shown in table I-1 to this subpart and equation I-1A to this section, or the consumption of each input gas, the default emission factors shown in table I-2 to this subpart, and equation I-1B to this section. Where: E i 2 S = 100 percent of annual manufacturing capacity of a facility as calculated using equation I-5 to this section (m 2 EF i 2 GWP i 0.001 = Conversion factor from kg to metric tons. i = Emitted gas. Where: E i 2 C i (1-U i 4 2 6 GWP i 0.001 = Conversion factor from kg to metric tons. i = Input gas. (2) If you manufacture LCDs, you must calculate annual production process emissions resulting from the use of each input gas for threshold applicability purposes using either the default emission factors shown in table I-1 to this subpart and equation I-2A to this section or the consumption of each input gas, the default emission factors shown in table I-2 to this subpart, and equation I-2B to this section. Where: E i 2 S = 100 percent of annual manufacturing capacity of a facility as calculated using equation I-5 to this section (m 2 EF i 2 GWP i 0.000001 = Conversion factor from g to metric tons. i = Emitted gas. Where: E i 2 C i (1-U i 4 2 6 GWP i 0.001 = Conversion factor from kg to metric tons. i = Input gas. (3) If you manufacture PVs, you must calculate annual production process emissions resulting from the use of each input gas i for threshold applicability purposes using gas-appropriate GWP values shown in table A-1 to subpart A of this part, the default emission factors shown in table I-2 to this subpart, and equation I-3 to this section. Where: E i 2 C i (1 - U i 4 2 6 GWP i 0.001 = Conversion factor from kg to metric tons. i = Input gas. (4) You must calculate total annual production process emissions for threshold applicability purposes using equation I-4 to this section. Where: E T 2 δ = Factor accounting for fluorinated heat transfer fluid emissions, estimated as 10 percent of total annual production process emissions at a semiconductor facility. Set equal to 1.1 when equation I-4 to this section is used to calculate total annual production process emissions from semiconductor manufacturing. Set equal to 1 when equation I-4 to this section is used to calculate total annual production process emissions from MEMS, LCD, or PV manufacturing. E i 2 i = Emitted gas. (b) You must calculate annual manufacturing capacity of a facility using equation I-5 to this section. Where: S = 100 percent of annual manufacturing capacity of a facility (m 2 W X 2 x = Month. [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012; 78 FR 68202, Nov. 13, 2013; 89 FR 31905, Apr. 25, 2024] § 98.92 GHGs to report. (a) You must report emissions of fluorinated GHGs (as defined in § 98.6), N 2 (1) Fluorinated GHGs emitted. (2)-(3) [Reserved] (4) N 2 (5) Emissions of fluorinated heat transfer fluids. (6) All fluorinated GHGs and N 2 (b) CO 2 4 2 [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10380, Feb. 22, 2012; 78 FR 68202, Nov. 13, 2013; 89 FR 31907, Apr. 25, 2024] § 98.93 Calculating GHG emissions. (a) You must calculate total annual emissions of each fluorinated GHG emitted by electronics manufacturing production processes from each fab (as defined in § 98.98) at your facility, including each input gas and each by-product gas. You must use either default gas utilization rates and by-product formations rates according to the procedures in paragraph (a)(1), (2), (6), or (7) of this section, as appropriate, or the stack test method according to paragraph (i) of this section, to calculate emissions of each input gas and each by-product gas. (1) If you manufacture semiconductors, you must adhere to the procedures in paragraphs (a)(1)(i) through (iii) of this section. You must calculate annual emissions of each input gas and of each by-product gas using equations I-6, I-7, and I-9 to this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab's annual consumption for that specific gas as calculated in equation I-11 to this section, plus any by-product emissions of that gas calculated under paragraph (a) of this section. Where: ProcesstypeE i E ij N = The total number of process sub-types j that depends on the electronics manufacturing fab and emission calculation methodology. If E ij i = Input gas. j = Process sub-type or process type. Where: ProcesstypeBE k BE kij N = The total number of process sub-types j that depends on the electronics manufacturing fab and emission calculation methodology. If BE kij i = Input gas. j = Process sub-type, or process type. k = By-product gas. (i) You must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching/wafer cleaning process type using default utilization and by-product formation rates as shown in table I-3 or I-4 to this subpart, and by using equations I-8A and I-8B to this section. Where: E ij C ij U ij a ij d ij UT ij 0.001 = Conversion factor from kg to metric tons. i = Input gas. j = Process sub-type or process type. Where: BE kij B kij e.g., 3 C ij a kij d kij UT kij kij ij 0.001 = Conversion factor from kg to metric tons. i = Input gas. j = Process sub-type or process type. k = By-product gas. (ii) You must calculate annual fab-level emissions of each fluorinated GHG used for each of the process sub-types associated with the chamber cleaning process type, including in-situ plasma chamber clean, remote plasma chamber clean, and in-situ thermal chamber clean, using default utilization and by-product formation rates as shown in table I-3 or I-4 to this subpart, and by using equations I-8A and I-8B to this section. (iii) If default values are not available for a particular input gas and process type or sub-type combination in tables I-3 or I-4, you must follow the procedures in paragraph (a)(6) of this section. (2) If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use § 98.3(a)(1) to calculate annual fab-level emissions for those processes. For all other tools and processes used to manufacture MEMs, LCD and PV, you must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching and chamber cleaning process types using default utilization and by-product formation rates as shown in table I-5, I-6, or I-7 to this subpart, as appropriate, and by using equations I-8A and I-8B to this section. If default values are not available for a particular input gas and process type or sub-type combination in tables I-5, I-6, or I-7 to this subpart, you must follow the procedures in paragraph (a)(6) of this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab's annual consumption for that specific gas as calculated in equation I-11 to this section, plus any by-product emissions of that gas calculated under this paragraph (a). (3)-(5) [Reserved] (6) If you are required, or elect, to perform calculations using default emission factors for gas utilization and by-product formation rates according to the procedures in paragraph (a)(1) or (2) of this section, and default values are not available for a particular input gas and process type or sub-type combination in tables I-3, I-4, I-5, I-6, or I-7 to this subpart, you must use a utilization rate (U ij i.e., ij 4 2 6 (7) If your fab employs hydrocarbon-fuel-based combustion emissions control systems (HC fuel CECS), including, but not limited to, abatement systems as defined at § 98.98, that were purchased and installed on or after January 1, 2025, to control emissions from tools that use either NF 3 2 4 4 2 2 4 Where: EAB CF4 4 2 C F2,j 2 U F2,j 2 a F2,j 2 4 4 2 2 UT F2,j 2 AB CF4,F2 2 4 CF4,F2 C NF3,RPC 3 B F2,NF3 2 3 a NF3,RPC 3 4 4 3 3 UT NF3,RPC,F2 2 3 NF3,RPC,F2 NF3,RPC j = Process type or sub-type. (b) You must calculate annual fab-level N 2 2 2 Where: E(N 2 j 2 2 C N2O,j 2 2 2 U N2O,j 2 a N2O,j 2 2 d N2O,j 2 2 UT N2O 2 2 2 2 2 2 0.001 = Conversion factor from kg to metric tons. j = Type of N 2 2 (1) You must use the factor for N 2 (2) You must use the factor for N 2 (c) You must calculate total annual input gas i consumption on a fab basis for each fluorinated GHG and N 2 where: C i I Bi I Ei A i D i i = Input gas. (d) You must calculate disbursements of input gas i using fab-wide gas-specific heel factors, as determined in § 98.94(b), and by using Equation I-12 of this subpart. Where a gas supply system serves more than one fab, Equation I-12 is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c). where: D i h il 2 il 2 N il F il X i i = Input gas. l = Size and type of gas container. M = The total number of different sized container types on a fab basis. If only one size and container type is used for an input gas i, M = 1. (e) You must calculate the amount of input gas i consumed, on a fab basis, for each process sub-type or process type j, using equation I-13 to this section. Where a gas supply system serves more than one fab, equation I-13 to this section is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c). If you elect to calculate emissions using the stack test method in paragraph (i) of this section and to use this paragraph (e) to calculate the fraction each fluorinated input gas i exhausted from tools with abatement systems and the fraction of each by-product gas k exhausted from tools with abatement systems, you may substitute “The set of tools with abatement systems” for “Process sub-type or process type” in the definition of “j” in equation I-13 to this section. where: C i,j f i,j C i i = Input gas. j = Process sub-type or process type. (f) [Reserved] (g) If you report controlled emissions pursuant to § 98.94(f), you must calculate the uptime of all the abatement systems for each combination of input gas or by-product gas, and process sub-type or process type, by using Equation I-15 of this subpart. Where: UT ij Td ijp ijp UT ijp i = Input gas. j = Process sub-type or process type. p = Abatement system. (h) If you use fluorinated heat transfer fluids, you must calculate the annual emissions of fluorinated heat transfer fluids on a fab basis using the mass balance approach described in Equation I-16 of this subpart. where: EH i Density i I iB P i N i R i I iE D i 0.001 = Conversion factor from kg to metric tons. i = Fluorinated heat transfer fluid. (1) If you use a fluorinated chemical both as a fluorinated heat transfer fluid and in other applications, you may calculate and report either emissions from all applications or from only those specified in the definition of fluorinated heat transfer fluids in § 98.6. (2) [Reserved] (i) Stack test method. (1)-(2) [Reserved] (3) Stack system stack test method. (i) You must measure the fab-specific fluorinated GHG consumption of the tools that are vented to the stack systems during the emission test as specified in § 98.94(j)(3). Calculate the consumption for each fluorinated GHG for the test period. (ii) You must calculate the emissions of each fluorinated GHG consumed as an input gas using equation I-17 to this section and each fluorinated GHG formed as a by-product gas using equation I-18 to this section and the procedures specified in paragraphs (i)(3)(ii)(A) through (E) of this section. If a stack system is comprised of multiple stacks, you must sum the emissions from each stack in the stack system when using equation I-17 or equation I-18 to this section. Where: E is X ism MW i Q s 3 SV = Standard molar volume of gas (0.0240 m 3 Δt m 1/10 3 i = Fluorinated GHG input gas. s = Stack system. N = Total number of time intervals m in sampling period. m = Time interval. Where: E ks X ks MW k Q s 3 SV = Standard molar volume of gas (0.0240 m 3 Δt m 1/10 3 k = Fluorinated GHG by-product gas. s = Stack system. N = Total number of time intervals m in sampling period. m = Time interval. (A) If a fluorinated GHG is consumed during the sampling period, but emissions are not detected, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X ism (B) If a fluorinated GHG is consumed during the sampling period and detected intermittently during the sampling period, use the detected concentration for the value of “X ism ism (C) If an expected or possible by-product, as listed in table I-17 to this subpart, is detected intermittently during the sampling period, use the measured concentration for “X ksm ksm (D) If a fluorinated GHG is not consumed during the sampling period and is an expected by-product gas as listed in table I-17 to this subpart and is not detected during the sampling period, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X ksm (E) If a fluorinated GHG is not consumed during the sampling period and is a possible by-product gas as listed in table I-17 to this subpart, and is not detected during the sampling period, then assume zero emissions for that fluorinated GHG for the tested stack system. (iii) You must calculate a fab-specific emission factor for each fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted per kg of input gas i consumed) in the tools that vent to stack systems, as applicable, using equations I-19A and I-19B to this section or equations I-19A and I-19C to this section. Use equation I-19A to this section to calculate the controlled emissions for each carbon-containing fluorinated GHG that would result during the sampling period if the utilization rate for the input gas were equal to 0.2 (E imax,f S s i,s imax,f S s i,s imax,f S s i,s imax,f Where: E imax,f Activity if = UT f = a if d if f = Fab. i = Fluorinated GHG input gas. Where: EF if E is Activity if = UT f a if = d if = f = Fab. i = Fluorinated GHG input gas. s = Stack system. EF if a if d if f = Fab. i = Fluorinated GHG input gas. (iv) You must calculate a fab-specific emission factor for each fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg of total fluorinated GHG consumed) in the tools vented to stack systems, as applicable, using equation I-20 to this section. When calculating the by-product emission factor for an input gas for which S s i,s imax,f S if Where: EF kf E ks Activity if UT f a kif d kif f = Fab. i = Fluorinated GHG input gas. k = Fluorinated GHG by-product gas. s = Stack system. (v) You must calculate annual fab-level emissions of each fluorinated GHG consumed using equation I-21 to this section. Where: E if EF if C if UT f a if d if f = Fab. i = Fluorinated GHG input gas. (vi) You must calculate annual fab-level emissions of each fluorinated GHG by-product formed using equation I-22 to this section. Where: E kf EF kf C if UT f a kif d kif f = Fab. i = Fluorinated GHG input gas. k = Fluorinated GHG by-product. (vii) When using the stack testing method described in this paragraph (i), you must calculate abatement system uptime on a fab basis using equation I-23 to this section. When calculating abatement system uptime for use in equation I-19 and I-20 to this section, you must evaluate the variables “Tdpf” and “UTpf” for the sampling period instead of the reporting year. Where: UT f Td pf UT pf f = Fab. p = Abatement system. (viii) When using the stack testing option described in this paragraph (i) and when using more than one DRE for the same input gas i or by-product gas k, you must calculate the weighted-average fraction of each fluorinated input gas i and each fluorinated by-product gas k that has more than one DRE and that is destroyed or removed in abatement systems for each fab f, as applicable, by using equation I-24A to this section (for input gases) and equation I-24B to this section (for by-product gases) and table I-18 to this subpart. If default values are not available in table I-18 for a particular input gas, you must use a value of 10. Where: d if d kif n i,p,DREy m i,q,DREz n i,p,a m i,q,a n k,i,p,DREy m k,i,q,DREz n k,i,p,a m k,i,q,a g i,p g k,i,p DRE y DRE z p = Chamber cleaning process sub-type. q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. f = Fab. i = Fluorinated GHG input gas. (ix) When using the stack testing method described in this paragraph (i), you must calculate the fraction each fluorinated input gas i exhausted in fab f from tools with abatement systems and the fraction of each by-product gas k exhausted from tools with abatement systems, as applicable, by following either the procedure set forth in paragraph (i)(3)(ix)(A) of this section or the procedure set forth in paragraph (i)(3)(ix)(B) of this section. (A) Use equation I-24C to this section (for input gases) and equation I-24D to this section (for by-product gases) and table I-18 to this subpart. If default values are not available in table I-18 for a particular input gas, you must use a value of 10. Where: a if n i,p,a m i,q,a n i,p m i,q g i,p p = Chamber cleaning process sub-type. q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. Where: a k,i,f n k,i,p,a m k,i,q,a n k,i,p m k,i,q g k,i,p p = Chamber cleaning process sub-type. q = Reference process type. There is one process type q that consists of the combination of etching and/or wafer cleaning processes. (B) Use paragraph (e) of this section to apportion consumption of gas i either to tools with abatement systems and tools without abatement systems or to each process type or sub-type, as applicable. If you apportion consumption of gas i to each process type or sub-type, calculate the fractions of input gas i and by-product gas k formed from gas i that are exhausted from tools with abatement systems based on the numbers of tools with and without abatement systems within each process type or sub-type. (4) Method to calculate emissions from fluorinated GHGs that are not tested. (5) [Reserved] [75 FR 74818, Dec. 1, 2010, as amended at 76 FR 59551, Sept. 27, 2011; 77 FR 10380, Feb. 22, 2012; 78 FR 68202, Nov. 13, 2013; 79 FR 25682, May 6, 2014; 79 FR 73783, Dec. 11, 2014; 79 FR 77391, Dec. 24, 2014; 81 FR 89253, Dec. 9, 2016; 89 FR 31907, Apr. 25, 2024] § 98.94 Monitoring and QA/QC requirements. (a) [Reserved] (b) For purposes of Equation I-12 of this subpart, you must estimate fab-wide gas-specific heel factors for each container type for each gas used, according to the procedures in paragraphs (b)(1) through (b)(5) of this section. This paragraph (b) does not apply to fluorinated GHGs or N 2 (1) Base your fab-wide gas-specific heel factors on the trigger point for change out of a container for each container size and type for each gas used. Fab-wide gas-specific heel factors must be expressed as the ratio of the trigger point for change out, in terms of mass, to the initial mass in the container, as determined by paragraphs (b)(2) and (3) of this section. (2) The trigger points for change out you use to calculate fab-wide gas-specific heel factors in paragraph (b)(1) of this section must be determined by monitoring the mass or the pressure of your containers. If you monitor the pressure, convert the pressure to mass using the ideal gas law, as displayed in Equation I-25 of this subpart, with the appropriate Z value selected based upon the properties of the gas. Where: p = Absolute pressure of the gas (Pa). V = Volume of the gas container (m 3 Z = Compressibility factor. n = Amount of substance of the gas (moles). R = Gas constant (8.314 Joule/Kelvin mole). T = Absolute temperature (K). (3) The initial mass you use to calculate a fab-wide gas-specific heel factor in paragraph (b)(1) of this section may be based on the weight of the gas provided to you in gas supplier documents; however, you remain responsible for the accuracy of these masses and weights under this subpart. (4) If a container is changed in an exceptional circumstance, as specified in paragraphs (b)(4)(i) and (ii) of this section, you must weigh that container or measure the pressure of that container with a pressure gauge, in place of using a heel factor to determine the residual weight of gas. When using mass-based trigger points for change out, you must determine if an exceptional circumstance has occurred based on the net weight of gas in the container, excluding the tare weight of the container. (i) For containers with a maximum storage capacity of less than 9.08 kg (20 lbs) of gas, an exceptional circumstance is a change out point that differs by more than 50 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type. (ii) For all other containers, an exceptional circumstance is a change out point that differs by more than 20 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type. (5) You must re-calculate a fab-wide gas-specific heel factor if you execute a process change to modify the trigger point for change out for a gas and container type that differs by more than 5 percent from the previously used trigger point for change out for that gas and container type. (c) You must develop apportioning factors for fluorinated GHG and N 2 (1) You must demonstrate that the fluorinated GHG and N 2 (2) You must demonstrate the accuracy of your fab-specific model by comparing the actual amount of input gas i consumed and the modeled amount of input gas i consumed in the fab, as follows: (i) You must analyze actual and modeled gas consumption for a period when the fab is at a representative operating level (as defined in § 98.98) lasting at least 30 days but no more than the reporting year. (ii) You must compare the actual gas consumed to the modeled gas consumed for one fluorinated GHG reported under this subpart for the fab. You must certify that the fluorinated GHG selected for comparison corresponds to the largest quantity, on a mass basis, of fluorinated GHG consumed at the fab during the reporting year for which you are required to apportion following the procedures specified in § 98.93(a), (b), or (i). You may compare the actual gas consumed to the modeled gas consumed for two fluorinated GHGs and demonstrate conformance according to paragraph (c)(2)(iii) of this section on an aggregate use basis for both fluorinated GHGs if one of the fluorinated GHGs selected for comparison corresponds to the largest quantity, on a mass basis, of fluorinated GHGs used at each fab that requires apportionment during the reporting year. (iii) You must demonstrate that the comparison performed for the largest quantity of gas(es), on a mass basis, consumed in the fab in paragraph (c)(2)(ii) of this section, does not result in a difference between the actual and modeled gas consumption that exceeds 20 percent relative to actual gas consumption, reported to two significant figures using standard rounding conventions. (iv) If you are required to apportion gas consumption and you use the procedures in § 98.93(i) to calculate annual emissions from a fab, you must verify your apportioning factors using the procedures in paragraphs (c)(2)(ii) and (iii) of this section such that the time period specified in paragraph (c)(2)(i) of this section and the last day you perform the sampling events specified under § 98.93(i)(3) occur in the same accounting month. (v) If your facility has multiple fabs with a single centralized fluorinated-GHG supply system, you must verify that your apportioning model can apportion fluorinated GHG consumption among the fabs by adhering to the procedures in paragraphs (c)(2)(ii) through (c)(2)(iv) of this section. (3) As an alternative to developing apportioning factors for fluorinated GHG and N 2 (d) [Reserved] (e) If you use HC fuel CECS purchased and installed on or after January 1, 2025 to control emissions from tools that use either NF 3 2 F2,j NF3,RPC 4 2 4 2 2 4 2 4 2 (f) If your fab employs abatement systems and you elect to reflect emission reductions due to these systems, or if your fab employs abatement systems designed for fluorinated GHG abatement and you elect to calculate fluorinated GHG emissions using the stack test method under § 98.93(i), you must comply with the requirements of paragraphs (f)(1) through (3) of this section. If you use an average of properly measured destruction or removal efficiencies for a gas and process sub-type or process type combination, as applicable, in your emission calculations under § 98.93(a), (b), and/or (i), you must also adhere to procedures in paragraph (f)(4) of this section. (1) You must certify and document that the abatement systems are properly installed, operated, and maintained according to the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9). (2) You must calculate and document the uptime of abatement systems using Equation I-15 or I-23 of this subpart, as applicable. (3) If you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), you must certify and document that the abatement systems at your facility for which you use default destruction or removal efficiency values are specifically designed for fluorinated GHG or N 2 2 2 2 2 2 (i) For purposes of paragraph (f)(3) of this section, destruction and removal efficiencies for abatement systems purchased and installed on or after January 1, 2025, must be measured using a scientifically sound, industry-accepted measurement methodology that accounts for dilution through the abatement system, such as EPA 430-R-10-003 (incorporated by reference, see § 98.7). (ii) Worst-case flow conditions are defined as the highest total fluorinated GHG or N 2 2 (4) If you calculate and report controlled emissions using neither the default destruction or removal efficiency values in table I-16 to this subpart nor an abatement system manufacturer-verified lower destruction or removal efficiency value per paragraph (f)(3) of this section, you must use an average of properly measured destruction or removal efficiencies for each gas and process sub-type or process type combination, as applicable, determined in accordance with procedures in paragraphs (f)(4)(i) through (vi) of this section. This includes situations in which your fab employs abatement systems not specifically designed for fluorinated GHG or N 2 2 (i) A properly measured destruction or removal efficiency value must be determined in accordance with EPA 430-R-10-003 (incorporated by reference, see § 98.7), or according to an alternative method approved by the Administrator (or authorized representative) as specified in paragraph (k) of this section. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may follow the alternative procedures specified in Appendix A to this subpart. (ii) You must select and properly measure the destruction or removal efficiency for a random sample of abatement systems to include in a random sampling abatement system testing program in accordance with procedures in paragraphs (f)(4)(ii)(A) and (B) of this section. (A) For the first 2 years for which your fab is required to report emissions of fluorinated GHG and N 2 (B) If testing of a randomly selected abatement system would be disruptive to production, you may replace that system with another randomly selected system for testing and return the system to the sampling pool for subsequent testing. Any one abatement system must not be replaced by another randomly selected system for more than three consecutive selections. When you have to replace a system in one year, you may select that specific system to be tested in one of the next two sampling years so that you may plan testing of that abatement system to avoid disrupting production. (iii) If you elect to take credit for abatement system destruction or removal efficiency before completing testing on 20 percent of the abatement systems for that gas and process sub-type or process type combination, as applicable, you must use default destruction or removal efficiencies or a verified destruction or removal efficiency, if verified at a lower value, for a gas and process type combination. You must not use a default value from table I-16 to this subpart for any abatement system not specifically designed for fluorinated GHG and N 2 (iv) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N 2 2 (v) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N 2 2 (vi) If your fab uses redundant abatement systems, you may account for the total abatement system uptime (that is, the time that at least one abatement system is in operational mode) calculated for a specific exhaust stream during the reporting year. (g) You must adhere to the QA/QC procedures of this paragraph when calculating fluorinated GHG and N 2 (1)-(2) [Reserved] (3) Follow the QA/QC procedures in accordance with those in EPA 430-R-10-003 (incorporated by reference, see § 98.7), or the applicable QA/QC procedures specified in an alternative method approved by the Administrator (or authorized representative) according to paragraph (k) of this section, when calculating abatement systems destruction or removal efficiencies. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), and you elect to follow the alternative procedures specified in Appendix A to this subpart according to paragraph (f)(4)(i) of this section, you must follow any additional QA/QC procedures specified in Appendix A to this subpart. (4) As part of normal operations for each fab, the inventory of gas stored in containers at the beginning of the reporting year must be the same as the inventory of gas stored in containers at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a). (h) You must adhere to the QA/QC procedures of this paragraph (h) when calculating annual gas consumption for each fluorinated GHG and N 2 (1) Review all inputs to Equations I-11 and I-16 of this subpart to ensure that all inputs and outputs are accounted for. (2) Do not enter negative inputs into the mass balance Equations I-11 and I-16 of this subpart and ensure that no negative emissions are calculated. (3) Ensure that the inventory at the beginning of one reporting year is identical to the inventory at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a) and (r). (4) Ensure that the total quantity of gas i in containers in service at the end of a reporting year is accounted for as if the in-service containers were full for Equation I-11 of this subpart. Ensure also that the same quantity is accounted for in the inventory of input gas i stored in containers at the beginning of the subsequent reporting year. (i) All flow meters, weigh scales, pressure gauges, and thermometers used to measure quantities that are monitored under this section or used in calculations under § 98.93 must meet the calibration and accuracy requirements specified in § 98.3(i). (j) Stack test methodology. (1) Stack system testing. (i) You must conduct an emission test during which the fab is operating at a representative operating level, as defined in § 98.98, and with the abatement systems connected to the stack system being tested operating with at least 90-percent uptime, averaged over all abatement systems, during the 8-hour (or longer) period for each stack system, or at no less than 90 percent of the abatement system uptime rate measured over the previous reporting year, averaged over all abatement systems. Hydrocarbon-fuel-based combustion emissions control systems that were purchased and installed on or after January 1, 2025, that are used to control emissions from tools that use either NF 3 2 4 (ii) You must measure for the expected and possible by-products identified in Table I-17 of this subpart and those fluorinated GHGs used as input fluorinated GHG in process tools vented to the stack system, except for any intermittent low-use fluorinated GHG as defined in § 98.98. You must calculate annual emissions of intermittent low-use fluorinated GHGs by adhering to the procedures in § 98.93(i)(4)(i). (iii) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack testing and does not meet the definition of intermittent low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas. If a fluorinated GHG consumed in the reporting year was not being consumed during the stack testing and is no longer in use by your fab (e.g., use of the gas has become obsolete or has been discontinued), then you must calculate annual emissions for that fluorinated GHG according to the procedure specified in § 98.93(i)(4). (iv) Although all applicable stack systems are not required to be tested simultaneously, you must certify that no significant changes in stack flow configuration occur between tests conducted for any particular fab in a reporting year. You must certify that no more than 10 percent of the total number of fluorinated GHG emitting process tools are connected or disconnected from a stack system during testing. You must also certify that no process tools that were in operation at the start of the test period have been moved to a different stack system during the test period (i.e., during or in between testing of individual stack systems) and that no point-of-use abatement systems have been permanently removed from service during the test period. You must document any changes in stack flow configuration in the emissions test data and report required to be kept as records under § 98.97(i)(4). (2) Test methods and procedures. (3) Fab-specific fluorinated GHG consumption measurements. (i) Measure fluorinated GHG consumption using gas flow meters, scales, or pressure measurements. Measure the mass or pressure, as applicable, at the beginning and end of the sampling period and when containers are changed out. If you elect to measure gas consumption using pressure (i.e., because the gas is stored in a location above its critical temperature) you must estimate consumption as specified in paragraphs (j)(3)(i)(A) and (B) of this section. (A) For each fluorinated GHG, you must either measure the temperature of the fluorinated GHG container(s) when the sampling periods begin and end and when containers are changed out, or measure the temperature of the fluorinated GHG container(s) every hour for the duration of the sampling period. Temperature measurements of the immediate vicinity of the containers (e.g., in the same room, near the containers) shall be considered temperature measurements of the containers. (B) Convert the sampling period-beginning, sampling period-ending, and container change-out pressures to masses using Equation I-25 of this subpart, with the appropriate Z value selected based upon the properties of the gas (e.g., the Z value yielded by the Redlich, Kwong, Soave equation of state with appropriate values for that gas). Apply the temperatures measured at or nearest to the beginning and end of the sampling period and to the time(s) when containers are changed out, as applicable. For each gas, the consumption during the sampling period is the difference between the masses of the containers of that gas at the beginning and at the end of the sampling period, summed across containers, including containers that are changed out. (ii) For each fluorinated GHG gas for which consumption is too low to be accurately measured during the sampling period using gas flow meters, scales, or pressure measurements as specified in paragraph (j)(3)(i) of this section, you must follow at least one of the procedures listed in paragraph (j)(3)(ii)(A) through (C) of this section to obtain a consumption measurement. (A) Draw the gas from a single gas container if it is normally supplied from multiple containers connected by a shared manifold. (B) Calculate consumption from pro-rated long-term consumption data (for example, calculate and use hourly consumption rates from monthly consumption data). (C) Increase the duration of the sampling period for consumption measurement beyond the minimum duration specified in Table I-9 of this subpart. (4) Emission test results. (5) Emissions testing frequency. (i) Annual testing. (ii) Criteria to test less frequently. i.e. (A) The relative standard deviation of the total CO 2 2 2 (B) The relative standard deviation for all single fluorinated GHGs that individually accounted for 5 percent or more of CO 2 (6) [Reserved] (7) Previous measurements. (i) Notify the Administrator (or an authorized representative) of your intention to use the results of the previous emissions testing. You must include in the notification the data and results you intend to use for meeting either reporting or recordkeeping requirements, a description of the method, and any deviations from the requirements in paragraph (j)(2) of this section. Your description must include an explanation of how any deviations do not affect the quality of the data collected. (ii) The Administrator will review the information submitted under paragraph (j)(7)(i) and determine whether the results of the previous emissions testing are adequate and issue an approval or disapproval of the use of the results within 120 days of the date on which you submit the notification specified in paragraph (j)(7)(i) of this section. (iii) If the Administrator finds reasonable grounds to disapprove the results of the previous emissions testing, the Administrator may request that you provide additional information to support the use of the results of the previous emissions testing. Failure to respond to any request made by the Administrator does not affect the 120 day deadline specified in paragraph (j)(7)(ii) of this section. (iv) Neither the approval process nor the failure to obtain approval for the use of results from previous emissions testing shall abrogate your responsibility to comply with the requirements of this subpart. (8) Scenarios that require a stack system to be re-tested. (i) Annual consumption of a fluorinated GHG used during the most recent emissions test (expressed in CO 2 2 2 2 (ii) A change in the consumption of an intermittent low-use fluorinated GHG (as defined in § 98.98) that was not used during the emissions test and not reflected in the fab-specific emission factor, such that it no longer meets the definition of an intermittent low-use fluorinated GHG. (iii) A decrease by more than 10 percent in the fraction of tools with abatement systems, compared to the number during the most recent emissions test. (iv) A change in the wafer size manufactured by the fab since the most recent emissions test. (v) [Reserved] (vi) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack test and does not meet the definition of intermittent, low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use as required in paragraph (j)(1)(iii) of this section. (k) You may request approval to use an alternative stack test method and procedure or to use an alternative method to determine abatement system destruction or removal efficiency by adhering to the requirements in paragraphs (k)(1) through (6) of this section. An alternative method is any method of sampling and analyzing for a fluorinated GHG or N 2 (1) You may use an alternative method from that specified in this subpart provided that you: (i) Notify the Administrator (or an authorized representative) of your intention to use an alternative method. You must include in the notification a site-specific test plan describing the alternative method and procedures (the alternative test plan), the range of test conditions over which the validation is intended to be applicable, and an alternative means of calculating the fab-level fluorinated GHG or N 2 (ii) Use Method 301 in appendix A of part 63 of this chapter to validate the alternative method. This may include the use of only portions of specific procedures of Method 301 if use of such procedures are sufficient to validate the alternative method; and (iii) Submit the results of the Method 301 validation process along with the notification of intention and the rationale for not using the specified method. (2) The Administrator will determine whether the validation of the proposed alternative method is adequate and issue an approval or disapproval of the alternative test plan within 120 days of the date on which you submit the notification and alternative test plan specified in paragraph (k)(1) of this section. If the Administrator approves the alternative test plan, you are authorized to use the alternative method(s) in place of the methods described in paragraph (f)(4)(i) of this section for measuring destruction or removal efficiency or paragraph (j) of this section for conducting the stack test, as applicable, taking into account the Administrator's comments on the alternative test plan. Notwithstanding the requirement in the preceding sentence, you may at any time prior to the Administrator's approval or disapproval proceed to conduct the stack test using the methods specified in paragraph (j) of this section or the destruction or removal efficiency determination specified in (f)(4)(i) of this section if you use a method specified in this subpart instead of the requested alternative. If an alternative test plan is not approved and you still want to use an alternative method, you must recommence the process to have an alternative test method approved starting with the notification of intent to use an alternative test method specified in paragraph (k)(1)(i) of this section. (3) You must report the results of stack testing or destruction or removal efficiency determination using the alternative method and procedure specified in the approved alternative test plan. You must include in your report for an alternative stack test method and for an alternative abatement system destruction or removal efficiency determination the information specified in paragraph (j)(4) of this section, including all methods, calculations and data used to determine the fluorinated GHG emission factor or the abatement system destruction or removal efficiency. The Administrator will review the results of the test using the alternative methods and procedure and then approve or deny the use of the results of the alternative test method and procedure no later than 120 days after they are submitted to EPA. (4) If the Administrator finds reasonable grounds to dispute the results obtained by an alternative method for the purposes of determining fluorinated GHG emissions or destruction or removal efficiency of an abatement system, the Administrator may require the use of another method specified in this subpart. (5) Once the Administrator has approved the use of the alternative method for the purposes of determining fluorinated GHG emissions for specific fluorinated GHGs and types of stack systems or abatement system destruction or removal efficiency, that method may be used at any other facility for the same fluorinated GHGs and types of stack systems, or fluorinated GHGs and abatement systems, if the approved conditions apply to that facility. In granting approval, the Administrator may limit the range of test conditions and emission characteristics for which that approval is granted and under which the alternative method may be used without seeking approval under paragraphs (k)(1) through (4) of this section. The Administrator will specify those limitations, if any, in the approval of the alternative method. (6) Neither the validation and approval process nor the failure to validate or obtain approval of an alternative method shall abrogate your responsibility to comply with the requirements of this subpart. [75 FR 74818, Dec. 1, 2010, as amended at 76 FR 36342, June 22, 2011; 76 FR 59551, Sept. 27, 2011; 77 FR 10380, Feb. 22, 2012; 77 FR 48089, Aug. 13, 2012; 78 FR 68209, Nov. 13, 2013; 79 FR 73785, Dec. 11, 2014; 81 FR 89255, Dec. 9, 2016; 89 FR 31913, Apr. 25, 2024] § 98.95 Procedures for estimating missing data. (a) Except as provided in paragraph (b) of this section, a complete record of all measured parameters used in the fluorinated GHG and N 2 (b) If you use fluorinated heat transfer fluids at your facility and are missing data for one or more of the parameters in Equation I-16 of this subpart, you must estimate fluorinated heat transfer fluid emissions using the arithmetic average of the emission rates for the reporting year immediately preceding the period of missing data and the months immediately following the period of missing data. Alternatively, you may estimate missing information using records from the fluorinated heat transfer fluid supplier. You must document the method used and values used for all missing data values. [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2012] § 98.96 Data reporting requirements. In addition to the information required by § 98.3(c), you must include in each annual report the following information for each electronics manufacturing facility: (a) Annual manufacturing capacity of each fab at your facility used to determine the annual manufacturing capacity of your facility in Equation I-5 of this subpart. (b) For facilities that manufacture semiconductors, the diameter of wafers manufactured at each fab at your facility (mm). (c) Annual emissions, on a fab basis as described in paragraph (c)(1) through (5) of this section. (1) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type for which your fab is required to calculate emissions as calculated in equations I-6, I-7, and I-9 to § 98.93. (2) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type or process sub-type as calculated in equations I-8A and I-8B to § 98.93, as applicable. (3) N 2 2 2 (4) Each fluorinated heat transfer fluid emitted as calculated in Equation 1-16 of this subpart. (5) When you use the procedures specified in § 98.93(i) of this subpart, annual emissions of each fluorinated GHG, on a fab basis. (d) The method of emissions calculation used in § 98.93 for each fab. (e) Annual production in terms of substrate surface area ( e.g., (f)-(l) [Reserved] (m) For the fab-specific apportioning model used to apportion fluorinated GHG and N 2 (1) Identification of the quantifiable metric used in your fab-specific engineering model to apportion gas consumption for each fab, and/or an indication if direct measurements were used in addition to, or instead of, a quantifiable metric. (2) The start and end dates selected under § 98.94(c)(2)(i). (3) Certification that the gas(es) you selected under § 98.94(c)(2)(ii) for each fab corresponds to the largest quantity(ies) consumed, on a mass basis, of fluorinated GHG used at your fab during the reporting year for which you are required to apportion. (4) The result of the calculation comparing the actual and modeled gas consumption under § 98.94(c)(2)(iii) and (iv), as applicable. (5) If you are required to apportion fluorinated GHG consumption between fabs as required by § 98.94(c)(2)(v), certification that the gas(es) you selected under § 98.94(c)(2)(ii) corresponds to the largest quantity(ies) consumed on a mass basis, of fluorinated GHG used at your facility during the reporting year for which you are required to apportion. (n) [Reserved] (o) For all HC fuel CECS that were purchased and installed on or after January 1, 2025, that are used to control emissions from tools that use either NF 3 2 2 4 2 4 (p) Inventory and description of all abatement systems through which fluorinated GHGs or N 2 (1) The number of abatement systems controlling emissions for each process sub-type, or process type, as applicable, for each gas used in the process sub-type or process type. (2) The basis of the destruction or removal efficiency being used (default, manufacturer-verified, or site-specific measurement according to § 98.94(f)(4)(i)) for each process sub-type or process type and for each gas. (q) For all abatement systems through which fluorinated GHGs or N 2 (1) Certification that all abatement systems at the facility have been installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9). (2) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), or (i), certification that the site maintenance plan for abatement systems for which emissions are being reported contains the manufacturer's recommendations and specifications for installation, operation, and maintenance for each abatement system. To use the default or lower manufacturer-verified destruction or removal efficiency values, operation of the abatement system must be within manufacturer's specifications, which may include, for example, specifications on vacuum pumps' purges, fuel and oxidizer settings, supply and exhaust flows and pressures, and utilities to the emissions control equipment including fuel gas flow and pressure, calorific value, and water quality, flow and pressure. (3) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N 2 2 2 (4) For all stack systems for which you calculate fluorinated GHG emissions according to the procedures specified in § 98.93(i)(3), certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3). (r) You must report an effective fab-wide destruction or removal efficiency value for each fab at your facility calculated using Equation I-26, I-27, and I-28 of this subpart, as appropriate. Where: DRE FAB FGHG i N 2 j 2 2 2 UAFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO 2 SFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO 2 C N 2 O,j 2 2 2 1-U N 2 O,j 2 2 GWP i GWP N 2 O 2 i = Fluorinated GHG. j = Process Type. (1) Use Equation I-27 of this subpart to calculate total unabated emissions, in metric tons CO 2 ij ij ijk Where: UAFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO 2 C ij 2 U ij GWP i GWP k B ijk i = Fluorinated GHG. j = Process Type. k = Fluorinated GHG by-product. (2) Use equation I-28 to this section to calculate total unabated emissions, in metric ton CO 2 if if kf if kif if ik Where: SFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO 2 EF if a if d if C if 2 EF kf a kif d ik GWP i GWP k i = Fluorinated GHG. k = Fluorinated GHG by-product. (s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the number of times missing data procedures were followed in the reporting year and the method used to estimate the missing data. (t)-(v) [Reserved] (w) If you elect to calculate fab-level emissions of fluorinated GHG using the stack test methods specified in § 98.93(i), you must report the following in paragraphs (w)(1) and (2) for each stack system, in addition to the relevant data in paragraphs (a) through (v) of this section: (1) The date of any stack testing conducted during the reporting year, and the identity of the stack system tested. (2) An inventory of all stack systems from which process fluorinated GHG are emitted. (x) If the emissions you report under paragraph (c) of this section include emissions from research and development activities, as defined in § 98.6, report the approximate percentage of total GHG emissions, on a metric ton CO 2 (y) If your semiconductor manufacturing facility manufactures wafers greater than 150 mm and emits more than 40,000 metric ton CO 2 (1) The first technology assessment report due after January 1, 2025, is due on March 31, 2028, and subsequent reports must be delivered every 5 years no later than March 31 of the year in which it is due. (2) The report must include the information described in paragraphs (y)(2)(i) through (v) of this section. (i) It must describe how the gases and technologies used in semiconductor manufacturing using 200 mm and 300 mm wafers in the United States have changed in the past 5 years and whether any of the identified changes are likely to have affected the emissions characteristics of semiconductor manufacturing processes in such a way that the default utilization and by-product formation rates or default destruction or removal efficiency factors of this subpart may need to be updated. (ii) It must describe the effect on emissions of the implementation of new process technologies and/or finer line width processes in 200 mm and 300 mm technologies, the introduction of new tool platforms, and the introduction of new processes on previously tested platforms. (iii) It must describe the status of implementing 450 mm wafer technology and the potential need to create or update default emission factors compared to 300 mm technology. (iv) It must provide any utilization and byproduct formation rates and/or destruction or removal efficiency data that have been collected in the previous 5 years that support the changes in semiconductor manufacturing processes described in the report. Any utilization or byproduct formation rate data submitted must be reported using both of the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this section if multiple fluorinated input gases are used, unless one of the input gases does not have a reference process utilization rate in table I-19 or I-20 to this subpart for the process type and wafer size whose emission factors are being measured, in which case the data must be submitted using the method specified in paragraph (y)(2)(iv)(A) of this section. If only one fluorinated input gas is fed into the process, you must use equations I-29A and I-29B to this section. In addition to using the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this section, you have the option to calculate and report the utilization or byproduct formation rate data using any alternative calculation methodology. The report must include the input gases used and measured, the utilization rates measured, the byproduct formation rates measured, the process type, the process subtype for chamber clean processes, the wafer size, and the methods used for the measurements. The report must also specify the method used to calculate each reported utilization and by-product formation rate, and provide a unique record number for each data set. For any destruction or removal efficiency data submitted, the report must include the input gases used and measured, the destruction and removal efficiency measured, the process type, the methods used for the measurements, and whether the abatement system is specifically designed to abate the gas measured under the operating conditions used for the measurement. If you choose to use an additional alternative calculation methodology to calculate and report the input gas emission factors and by-product formation rates, you must provide a complete, mathematical description of the alternative method used (including the equation used to calculate each reported utilization and by-product formation rate) and include the information in this paragraph (y)(2)(iv). (A) All-input gas method. ij i g Where: U ij E i Mass i i = Fluorinated GHG. j = Process type. Where: BEF kji E k Mass i i = Fluorinated GHG. j = Process type. k = Fluorinated GHG by-product. Where: U ij Where: BEF ijg E i Mass i Mass g i = Fluorinated GHG. g = Fluorinated GHG input gas, where gas g is not equal to gas i. j = Process type. (B) Reference emission factor method. Where: U ij U ijr E i Mass i Mass g BEF ijgr i = Fluorinated GHG. g = Fluorinated GHG input gas, where gas g is not equal to gas i. r = Reference data. Where: BEF ijg BEF ijgr U ijr E i Mass i Mass g i = Fluorinated GHG. j = Process type. g = Fluorinated GHG input gas, where gas g is not equal to gas i. r = Reference data. (v) It must describe the use of a new gas, use of an existing gas in a new process type or sub-type, or a fundamental change in process technology. (3) If, on the basis of the information reported in paragraph (y)(2) of this section, the report indicates that GHG emissions from semiconductor manufacturing may have changed from those represented by the default utilization and by-product formation rates in Tables I-3 or I-4, or the default destruction or removal efficiency values in Table I-16 of this subpart, the report must lay out a data gathering and analysis plan focused on the areas of potential change. The plan must describe the elements in paragraphs (y)(3)(i) and (ii). (i) The testing of tools to determine the potential effect on current utilization and by-product formation rates and destruction or removal efficiency values under the new conditions. (ii) A planned analysis of the effect on overall facility emissions using a representative gas-use profile for a 200 mm, 300 mm, or 450 mm fab (depending on which technology is under consideration). (4) Multiple semiconductor manufacturing facilities may submit a single consolidated technology assessment report as long as the facility identifying information in § 98.3(c)(1) and the certification statement in § 98.3(c)(9) is provided for each facility for which the consolidated report is submitted. (5) The Administrator will review the report received and determine whether it is necessary to update the default utilization rates and by-product formation rates in Tables I-3, I-4, I-11, and I-12 of this subpart and default destruction or removal efficiency values in Table I-16 of this subpart based on the following: (i) Whether the revised default utilization and by-product formation rates and destruction or removal efficiency values will result in a projected shift in emissions of 10 percent or greater. (ii) Whether new platforms, processes, or facilities that are not captured in current default utilization and by-product formation rates and destruction or removal efficiency values should be included in revised values. (iii) Whether new data are available that could expand the existing data set to include new gases, tools, or processes not included in the existing data set (i.e. gases, tools, or processes for which no data are currently available). (6) The Administrator will review the reports within 120 days and will notify you of a determination whether it is necessary to update any default utilization and by-product formation rates and/or destruction or removal efficiency values. If the Administrator determines it is necessary to update default utilization and by-product formation rates and/or destruction or removal efficiency values, you will then have 180 days from the date you receive notice of the determination to execute the data collection and analysis plan described in the report and submit those data to the Administrator. [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2010; 78 FR 68215, Nov. 13, 2013; 78 FR 71954, Nov. 29, 2013; 79 FR 73785, Dec. 11, 2014; 81 FR 9255, Dec. 9, 2016; 89 FR 31915, Apr. 25, 2024] § 98.97 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the following records: (a) All data used and copies of calculations made as part of estimating gas consumption and emissions, including all spreadsheets. (b) If you use HC fuel CECS purchased and installed on or after January 1, 2025, to control emissions from tools that use either NF 3 2 F2,j NF3,RPC 4 2 4 2 4 2 e.g., 4 2 4 2 4 2 (c) Documentation for the fab-specific engineering model used to apportion fluorinated GHG and N 2 (1) A clear, detailed description of the fab-specific model, including how it was developed; the quantifiable metric used in the model; all sources of information, equations, and formulas, each with clear definitions of terms and variables; all apportioning factors used to apportion fluorinated GHG and N 2 2 (2) Sample calculations used for developing the gas apportioning factors (f ij (3) If you develop apportioning factors through the use of direct measurement according to § 98.94(c)(3), calculations and data used to develop each gas apportioning factor. (4) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the apportioning model verification specified in § 98.94(c). (d) For all abatement systems through which fluorinated GHGs or N 2 (1) Records of the information in paragraphs (d)(1)(i) though (iv) of this section: (i) Documentation to certify that each abatement system or group of abatement systems is installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is specified in paragraph (d)(9) of this section. (ii) Documentation from the abatement system supplier describing the abatement system's designed purpose and emission control capabilities for fluorinated GHG and N 2 (iii) If you use either default destruction or removal efficiency values or certified destruction or removal efficiency values that are lower than the default values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG and N 2 (iv) Certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3), as required under § 98.94(f)(3). (2) Abatement system calibration and maintenance records. (3) Where either the default destruction or removal efficiency value or a certified destruction or removal efficiency value that is lower than the default is used, documentation from the abatement system supplier describing the equipment's designed purpose and emission control capabilities for fluorinated GHG and N 2 (4) Where properly measured site-specific destruction or removal efficiencies are used to report emissions, the information in paragraphs (d)(4)(i) though (vi) of this section: (i) Dated certification by the technician who made the measurement that the destruction or removal efficiency is calculated in accordance with methods in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable Appendix A of this subpart, or an alternative method approved by the Administrator as specified in § 98.94(k), complete documentation of the results of any initial and subsequent tests, the final report as specified in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable, the records and documentation specified in Appendix A of this subpart including the information required in paragraph (b)(7) of Appendix A of this subpart, or a final report as specified in an alternative method approved by the Administrator as specified in § 98.94(k). (ii) The average destruction or removal efficiency of the abatement systems operating during the reporting year for each process type and gas combination. (iii) A description of the calculation used to determine the average destruction or removal efficiency for each process type and gas combination, including all inputs to the calculation. (iv) The records of destruction or removal efficiency measurements for abatement systems for all tests that have been used to determine the site-specific destruction or removal efficiencies currently being used. (v) A description of the method used for randomly selecting abatement systems for testing. (vi) The total number of systems for which destruction or removal efficiency was properly measured for each process type and gas combination for the reporting year. (5) In addition to the inventory specified in § 98.96(p), the information in paragraphs (d)(5)(i) through (iii) of this section: (i) The number of abatement systems of each manufacturer, and model numbers, and the manufacturer's certified fluorinated GHG and N 2 (ii) Records of destruction or removal efficiency measurements over the in-use life of each abatement system. (iii) A description of the tool, with the process type or sub-type, for which the abatement system treats exhaust. (6) Records of all inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, in accordance with equations I-15 or I-23 to § 98.93, as applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value, lower manufacturer-verified value, or a measured site-specific value. (7) Records of all inputs and results of calculations made to determine the average weighted fraction of each gas destroyed or removed in the abatement systems for each stack system using equations I-24A and I-24B to § 98.93, if applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value, lower manufacturer-verified value, or a measured site-specific value. (8) Records of all inputs and the results of the calculation of the facility-wide emission destruction or removal efficiency factor calculated according to Equations I-26, I-27, and I-28 of this subpart. (9) A site maintenance plan for abatement systems, which must be maintained on-site at the facility as part of the facility's GHG Monitoring Plan as described in § 98.3(g)(5), and be developed and implemented according to paragraphs (d)(9)(i) through (iii) of this section. (i) The site maintenance plan for abatement systems must be based on the abatement system manufacturer's recommendations and specifications for installation, operation, and maintenance if you use default or lower manufacturer-verified destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If the manufacturer's recommendations and specifications for installation, operation, and maintenance are not available, you cannot use default destruction and removal efficiency values or lower manufacturer-verified value in your emissions calculations under § 98.93(a), (b), and/or (i). If you use an average of properly measured destruction or removal efficiencies determined in accordance with the procedures in § 98.94(f)(4)(i) through (vi), the site maintenance plan for abatement systems must be based on the abatement system manufacturer's recommendations and specifications for installation, operation, and maintenance, where available. If you deviate from the manufacturer's recommendations and specifications, you must include documentation that demonstrates how the deviations do not negatively affect the performance or destruction or removal efficiency of the abatement systems. (ii) The site maintenance plan for abatement systems must include a defined preventative maintenance process and checklist. (iii) The site maintenance plan for abatement systems must include a corrective action process that you must follow whenever an abatement system is found to be not operating properly. (e) Purchase records for gas purchased. (f) Invoices for gas purchases and sales. (g) Documents and records used to monitor and calculate abatement system uptime. (h) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. You must update your GHG Monitoring Plan to comply with § 98.94(c) consistent with the requirements in § 98.3(g)(5)(iii). (i) Retain the following records for each fab for which you elect to calculate fab-level emissions of fluorinated GHG using the procedures specified in § 98.93(i)(3) or (4). (1) [Reserved] (2) For each stack system, identify the method used to calculate annual emissions; either § 98.93(i)(3) or (4). (3) The identity and total annual consumption of each gas identified as an intermittent low use fluorinated GHG as specified in § 98.93(i)(4)(i) and defined in § 98.98. (4) The emissions test data and reports (see § 98.94(j)(4)) and the calculations used to determine the fab-specific emission factor, including the actual fab-specific emission factor, the average hourly emission rate of each fluorinated GHG from the stack system during the test and the stack system activity rate during the test. The report must also contain any changes in the stack system configuration during or between tests in a reporting year. (5) The fab-specific emission factor and the calculations and data used to determine the fab-specific emission factor for each fluorinated GHG and by-product, as calculated using equations I-19A, I-19B, I-19C and I-20 to § 98.93(i)(3). (6) Calculations and data used to determine annual emissions of each fluorinated GHG for each fab. (7) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the stack testing period. (8) A copy of the certification that no significant changes in stack system flow configuration occurred between tests conducted for any particular fab in a reporting year, as required by § 98.94(j)(1)(iv) and any calculations and data supporting the certification. (9) The number of tools vented to each stack system in the fab and all inputs and results for the calculations accounting for the fraction of gas exhausted through abatement systems using equations I-24C and I-24D to § 98.93. (j) If you report the approximate percentage of total GHG emissions from research and development activities under § 98.96(x), documentation for the determination of the percentage of total emissions of each fluorinated GHG and/or N 2 (k) Annual gas consumption for each fluorinated GHG and N 2 2 (l) All inputs used to calculate gas consumption in Equation I-11 of this subpart, for each fluorinated GHG and N 2 (m) Annual amount of each fluorinated GHG consumed for process sub-type, process type, stack system, or fab, as appropriate, and the annual amount of N 2 (n) Disbursements for each fluorinated GHG and N 2 2 2 (o) Fraction of each fluorinated GHG or N 2 (p) Fraction of each fluorinated GHG or N 2 (q) All inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, or during an emissions sampling period, in accordance with Equations I-15 and/or I-23 of this subpart, as applicable. (r) For fluorinated heat transfer fluid emissions, inputs to the fluorinated heat transfer fluid mass balance equation, Equation I-16 of this subpart, for each fluorinated heat transfer fluid used. (s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the estimates of those data. [75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68218, Nov. 13, 2013; 81 FR 9255, Dec. 9, 2016; 89 FR 31918, Apr. 25, 2024] § 98.98 Definitions. 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 takes precedence for the reporting requirements in this subpart. Abatement system 2 2 2 2 2 Actual gas consumption By-product formation Chamber cleaning (1) In situ plasma process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent that is dissociated into its cleaning constituents by a plasma generated inside the chamber where the film is produced. (2) Remote plasma process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent dissociated by a remotely located plasma source. (3) In situ thermal process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent that is thermally dissociated into its cleaning constituents inside the chamber where thin films are produced. Controlled emissions e.g., Destruction or removal efficiency (DRE) 2 2 2 Fab Fully fluorinated GHGs 6 3 5 3 4 8 Gas utilization 2 Heel Hydrocarbon-fuel based combustion emission control system (HC fuel CECS) 2 2 Input gas 2 Intermittent low-use fluorinated GHG (1) The fluorinated GHG is used by the fab but is not used during the period of stack testing for the fab/stack system. (2) The emissions of the fluorinated GHG, estimated using the methods in § 98.93(i)(4) do not constitute more than 5 percent of the total fluorinated GHG emissions from the fab on a CO 2 (3) The sum of the emissions of all fluorinated GHGs that are considered intermittent low use gases does not exceed 10,000 metric tons CO 2 (4) The fluorinated GHG is not an expected or possible by-product identified in Table I-17 of this subpart. Maximum substrate starts Modeled gas consumed Nameplate capacity Operational mode Plasma etching 2 X 3 4 w X y z Process sub-type Process types Properly measured destruction or removal efficiency The Random Sampling Abatement System Testing Program (RSASTP) Redundant abatement systems 2 2 2 Repeatable Representative operating levels Stack system Trigger point for change out Unabated emissions 2 2 2 Uptime Wafer cleaning Wafer passes Wafer starts [75 FR 74818, Dec. 1, 2010, as amended at 77 FR 10381, Feb. 22, 2012; 78 FR 68220, Nov. 13, 2013; 89 FR 31919, Apr. 25, 2024] Table I-1 to Subpart I of Part 98—Default Emission Factors for Manufacturing Capacity-Based Threshold Applicability Determination Table I-1 to Subpart I of Part 98—Default Emission Factors for Manufacturing Capacity-Based Threshold Applicability Determination Product type Emission factors EF i CF 4 C 2 6 CHF 3 c-C 4 8 C 3 8 NF 3 SF 6 N 2 Semiconductors (kg/m 2 0.9 1.0 0.04 NA 0.05 0.04 0.20 NA LCD (g/m 2 0.65 NA 0.0024 0.00 NA 1.29 4.14 17.06 MEMS (kg/m 2 0.015 NA NA 0.076 NA NA 1.86 NA Notes: [89 FR 31919, Apr. 25, 2024] Table I-2 to Subpart I of Part 98—Default Emission Factors for Gas Consumption-Based Threshold Applicability Determination Table I-2 to Subpart I of Part 98—Default Emission Factors for Gas Consumption-Based Threshold Applicability Determination Process gas i Fluorinated GHGs N 2 1-U i 0.8 1 BCF 4 0.15 0 BC 2 6 0.05 0 [89 FR 31919, Apr. 25, 2024] Table I-3 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk mm mm Table I-3 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk mm mm Process type/sub-type Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 2 5 CH 3 C 3 8 C 4 8 NF 3 SF 6 C 4 6 C 5 8 C 4 8 Etching/Wafer Cleaning 1-U i 0.73 0.72 0.51 0.13 0.064 0.70 NA 0.14 0.19 0.55 0.083 0.072 NA BCF 4 NA 0.10 0.085 0.079 0.077 NA NA 0.11 0.0040 0.13 0.095 NA NA BC 2 6 0.041 NA 0.035 0.025 0.024 0.0034 NA 0.037 0.025 0.11 0.073 0.014 NA BC 4 8 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA BCHF 3 0.091 0.047 NA 0.049 NA NA NA 0.040 NA 0.0012 0.066 0.0039 NA Chamber Cleaning In situ plasma cleaning 1-U i 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14 BCF 4 NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13 BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA 0.045 BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA Remote plasma cleaning 1-U i NA NA NA NA NA NA NA NA 0.028 NA NA NA NA BCF 4 NA NA NA NA NA NA NA NA 0.015 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA BF 2 NA NA NA NA NA NA NA NA 0.5 NA NA NA NA In situ thermal cleaning 1-U i NA NA NA NA NA NA NA NA NA NA NA NA NA BCF 4 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA Notes: i.e., [89 FR 31920, Apr. 25, 2024] Table I-4 to Subpart I of Part 98—

Default Emission Factors (1-U ij ij ijk mm mm Table I-4 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk mm mm Process type/sub-type Process gas i CF 4 C 2 6 CHF 3 CH 2 2 CH 3 C 3 8 C 4 8 NF 3 SF 6 C 4 6 C 5 8 C 4 8 Etching/Wafer Cleaning 1-U i 0.65 0.80 0.37 0.20 0.30 0.30 0.18 0.16 0.30 0.15 0.10 NA BCF 4 NA 0.21 0.076 0.060 0.0291 0.21 0.045 0.044 0.033 0.059 0.11 NA BC 2 6 0.058 NA 0.058 0.043 0.009 0.018 0.027 0.045 0.041 0.062 0.083 NA BC 4 8 0.0046 NA 0.0027 0.054 0.0070 NA NA NA NA 0.0051 NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA 0.00012 NA BCHF 3 0.012 NA NA 0.057 0.016 0.012 0.028 0.023 0.0039 0.017 0.0069 NA BCH 2 2 0.005 NA 0.0024 NA 0.0033 NA 0.0021 0.00074 0.000020 0.000030 NA NA BCH 3 0.0061 NA 0.027 0.0036 NA 0.00073 0.0063 0.0080 0.0082 0.00065 NA NA Chamber Cleaning In situ plasma cleaning 1-U i NA NA NA NA NA NA NA 0.20 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.037 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA Remote plasma cleaning 1-U i NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.037 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA BCHF 3 NA NA NA NA NA NA NA 0.000059 NA NA NA NA BCH 2 2 NA NA NA NA NA NA NA 0.00088 NA NA NA NA BCH 3 NA NA NA NA NA NA NA 0.0028 NA NA NA NA BF 2 NA NA NA NA NA NA NA 0.5 NA NA NA NA In situ thermal cleaning 1-U i NA NA NA NA NA NA NA 0.28 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.010 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA Notes: i.e., [89 FR 31921, Apr. 25, 2024] Table I-5 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk Process type factors Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 3 8 c− C 4 8 NF 3 NF 3 SF 6 C 4 6a C 5 8a C 4 8 a Etch 1-U i 0.7 1 1 1 NA 1 NA 0.2 0.2 0.1 0.2 NA Etch BCF 4 NA 1 1 1 NA 0.2 NA NA NA 1 0.2 NA Etch BC 2 6 NA NA NA NA NA 0.2 NA NA NA 1 0.2 NA CVD Chamber Cleaning 1-U i 0.9 0.6 NA NA 0.4 0.1 0.02 0.2 NA NA 0.1 0.1 CVD Chamber Cleaning BCF 4 NA 0.1 NA NA 0.1 0.1 2 2 NA NA 0.1 0.1 CVD Chamber Cleaning BC 3 8 NA NA NA NA NA NA NA NA NA NA NA 0.4 Notes: 1 2 [75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013] Table I-6 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk Process type factors Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 3 8 c− C 4 8 NF 3 NF 3 SF 6 Etch 1-U i 0.6 NA 0.2 NA NA 0.1 NA NA 0.3 Etch BCF 4 NA NA 0.07 NA NA 0.009 NA NA NA Etch BCHF 3 NA NA NA NA NA 0.02 NA NA NA Etch BC 2 4 NA NA 0.05 NA NA NA NA NA NA CVD Chamber Cleaning 1-U i NA NA NA NA NA NA 0.03 0.3 0.9 Notes: [75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013] Table I-7 To Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk Process type factors Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 3 8 c− C 4 8 NF 3 NF 3 SF 6 Etch 1-U i 0.7 0.4 0.4 NA NA 0.2 NA NA 0.4 Etch BCF 4 NA 0.2 NA NA NA 0.1 NA NA NA Etch BC 2 6 NA NA NA NA NA 0.1 NA NA NA CVD Chamber Cleaning 1-U i NA 0.6 NA NA 0.1 0.1 NA 0.3 0.4 CVD Chamber Cleaning BCF 4 NA 0.2 NA NA 0.2 0.1 NA NA NA Notes: [75 FR 74818, Dec. 1, 2010, as amended at 78 FR 68225, Nov. 13, 2013] Table I-8 to Subpart I of Part 98—Default Emission Factors (1-UN 2 ,j 2 2 ,j Table I-8 to Subpart I of Part 98—Default Emission Factors (1-UN 2 ,j 2 2 ,j Manufacturing type/process type/wafer size N 2 Semiconductor Manufacturing: 200 mm or Less: CVD 1-U i 1.0 Other Manufacturing Process 1-U i 1.0 300 mm or greater: CVD 1-U i 0.5 Other Manufacturing Process 1-U i 1.0 LCD Manufacturing: CVD Thin Film Manufacturing 1-U i 0.63 All other N 2 1.0 [89 FR 31921, Apr. 25, 2024] Table I-9 to Subpart I of Part 98—Methods and Procedures for Conducting Emissions Test for Stack Systems [78 FR 68227, Nov. 13, 2013] Table I-10 to Subpart I of Part 98—Maximum Field Detection Limits Applicable to Fluorinated GHG Concentration Measurements for Stack Systems Fluorinated GHG Analyte Maximum field CF 4 20 C 2 6 20 C 3 8 20 C 4 6 20 C 5 8 20 c-C 4 8 20 CH 2 2 40 CH 3 40 CHF 3 20 NF 3 20 SF 6 4 Other fully fluorinated GHGs 20 Other fluorinated GHGs 40 ppbv—Parts per billion by volume. [78 FR 68228, Nov. 13, 2013] Table I-11 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk Table I-11 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk [150 mm and 200 mm Wafers] All processes Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 2 5 CH 3 C 3 8 C 4 8 NF 3 NF 3 SF 6 C 4 6 C 5 8 C 4 8 1-U i 0.79 0.55 0.51 0.13 0.064 0.70 0.40 0.12 0.18 0.028 0.58 0.083 0.072 0.14 BCF 4 NA 0.19 0.085 0.079 0.077 NA 0.20 0.11 0.11 0.015 0.13 0.095 NA 0.13 BC 2 6 0.027 NA 0.035 0.025 0.024 0.0034 NA 0.019 0.0059 NA 0.10 0.073 0.014 0.045 BC 4 8 NA NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA NA BC 5 8 0.00077 NA 0.0012 NA NA NA NA 0.0043 NA NA NA NA NA NA BCHF 3 0.060 0.0020 NA 0.049 NA NA NA 0.020 NA NA 0.0011 0.066 0.0039 NA BF 2 NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA Notes: i.e. [89 FR 31921, Apr. 25, 2024] Table I-12 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk Table I-12 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk [300 mm and 450 mm Wafers] All processes Process gas i CF 4 C 2 6 CHF 3 CH 2 2 CH 3 C 3 8 C 3 8 C 4 8 NF 3 NF 3 SF 6 C 4 6 C 5 8 C 4 8 1-U i 0.65 0.80 0.37 0.20 0.30 0.30 0.063 0.183 0.19 0.018 0.30 0.15 0.100 NA BCF 4 NA 0.21 0.076 0.060 0.029 0.21 NA 0.045 0.040 0.037 0.033 0.059 0.109 NA BC 2 6 0.058 NA 0.058 0.043 0.0093 0.18 NA 0.027 0.0204 NA 0.041 0.062 0.083 NA BC 4 6 0.0083 NA 0.01219 NA 0.001 NA NA 0.008 NA NA NA NA NA NA BC 4 8 0.0046 NA 0.00272 0.054 0.007 NA NA NA NA NA NA 0.0051 NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA 0.00012 NA BCH 2 2 0.005 NA 0.0024 NA 0.0033 NA NA 0.0021 0.00034 0.00088 0.000020 0.000030 NA NA BCH 3 0.0061 NA 0.027 0.0036 NA 0.0007 NA 0.0063 0.0036 0.0028 0.0082 0.00065 NA NA BCHF 3 0.012 NA NA 0.057 0.016 0.012 NA 0.028 0.0106 0.000059 0.0039 0.017 0.0069 NA BF 2 NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA [89 FR 31922, Apr. 25, 2024] Table I-13 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk [78 FR 68231, Nov. 13, 2013] Table I-14 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk [78 FR 68232, Nov. 13, 2013] Table I-15 to Subpart I of Part 98—Default Emission Factors (1-U ij ij ijk [78 FR 68233, Nov. 13, 2013] Table I-16 to Subpart I of Part 98—Default Emission Destruction or Removal Efficiency (DRE) Factors for Electronics Manufacturing Table I-16 to Subpart I of Part 98—Default Emission Destruction or Removal Efficiency (DRE) Factors for Electronics Manufacturing Manufacturing type/process type/gas Default DRE MEMS, LCDs, and PV Manufacturing 60 Semiconductor Manufacturing: CF 4 87 CH 3 98 CHF 3 97 CH 2 2 98 C 4 8 93 C 4 8 93 C 5 8 97 C 4 6 95 C 3 8 98 C 2 5 97 C 2 6 98 SF 6 95 NF 3 96 All other carbon-based fluorinated GHGs used in Semiconductor Manufacturing 60 N 2 CVD and all other N 2 60 [89 FR 31922, Apr. 25, 2024] Table I-17 to Subpart I of Part 98—Expected and Possible By-Products for Electronics Manufacturing For each stack system for which you use the “stack test method” to calculate annual emissions, you must measure the following: If emissions are detected intermittently, use the If emissions are not detected, use the Expected By-products: 4 2 6 3 2 2 3 Use the measured concentration for “X ksm ksm Use one-half of the field detection limit you determined for the fluorinated GHG according to § 98.94(j)(2) for the value of “X ksm Possible By-products: 3 8 4 6 4 8 5 8 Use the measured concentration for “X ksm ksm Assume zero emissions for that fluorinated GHG for the tested stack system. [78 FR 68234, Nov. 13, 2013] Table I-18 to Subpart I of Part 98—Default Factors for Gamma ( g i,p g k,i,p Table I-18 to Subpart I of Part 98—Default Factors for Gamma (g i,p k,i,p Process type In-situ thermal or in-situ plasma cleaning Remote plasma cleaning Gas CF 4 C 2 6 c-C 4 8 NF 3 SF 6 C 3 8 CF 4 NF 3 If manufacturing wafer sizes ≤200 mm AND manufacturing 300 mm (or greater) wafer sizes g i 13 9.3 4.7 14 11 NA NA 5.7 g CF4,i NA 23 6.7 63 8.7 NA NA 58 g C2F6,i NA NA NA NA 3.4 NA NA NA g CHF3,i NA NA NA NA NA NA NA 0.24 g CH2F2,i NA NA NA NA NA NA NA 111 g CH3F,i NA NA NA NA NA NA NA 33 If manufacturing ≤200 mm OR manufacturing 300 mm (or greater) wafer sizes g i 13 9.3 4.7 2.9 11 NA NA 1.4 g CF4,i NA 23 6.7 110 8.7 NA NA 36 g C2F6,i NA NA NA NA 3.4 NA NA NA g i NA NA NA 26 NA NA NA 10 g CF4,i NA NA NA 17 NA NA NA 80 g C2F6,i NA NA NA NA NA NA NA NA g CHF3,i NA NA NA NA NA NA NA 0.24 g CH2F2,i NA NA NA NA NA NA NA 111 g CH3F,i NA NA NA NA NA NA NA 33 * If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use the corresponding g in this table. For all other tools and processes, a default g of 10 must be used. [89 FR 31922, Apr. 25, 2024] Table I-19 to Subpart I of Part 98—Reference Emission Factors (1-U ij ij ijk Table I-19 to Subpart I of Part 98—Reference Emission Factors (1-U ij ij ijk Process type/sub-type Process gas i CF 4 C 2 6 CHF 3 CH 2 2 C 2 5 CH 3 C 3 8 C 4 8 NF 3 SF 6 C 4 6 C 5 8 C 4 8 Etching/Wafer Cleaning 1-U i 0.73 0.46 0.31 0.37 0.064 0.66 NA 0.21 0.20 0.55 0.086 0.072 NA BCF 4 NA 0.20 0.10 0.031 0.077 NA NA 0.17 0.0040 0.023 0.0089 NA NA BC 2 6 0.029 NA NA NA NA NA NA 0.065 NA NA 0.045 0.014 NA BC 4 6 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 4 8 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 5 8 NA NA NA NA NA NA NA 0.016 NA NA NA NA NA BCHF 3 0.13 NA NA NA NA NA NA NA NA NA NA 0.0039 NA Chamber Cleaning In situ plasma cleaning 1-U i 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14 BCF 4 NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13 BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA 0.045 BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA Remote plasma cleaning 1-U i NA NA NA NA NA NA NA NA 0.028 NA NA NA NA BCF 4 NA NA NA NA NA NA NA NA 0.015 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA In situ thermal cleaning 1-U i NA NA NA NA NA NA NA NA NA NA NA NA NA BCF 4 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA NA [89 FR 31923, Apr. 25, 2024] Table I-20 to Subpart I of Part 98—Reference Emission Factors (1-U ij ij ijk Table I-20 to Subpart I of Part 98—Reference Emission Factors (1-U ij ij ijk Process type/sub-type Process gas i CF 4 C 2 6 CHF 3 CH 2 2 CH 3 C 3 8 C 4 8 NF 3 SF 6 C 4 6 C 5 8 C 4 8 Etching/Wafer Cleaning 1-U i 0.68 0.80 0.35 0.15 0.34 0.30 0.16 0.17 0.28 0.17 0.10 NA BCF 4 NA 0.21 0.073 0.020 0.038 0.21 0.045 0.035 0.0072 0.034 0.11 NA BC 2 6 0.041 NA 0.040 0.0065 0.0064 0.18 0.030 0.038 0.0017 0.025 0.083 NA BC 4 6 0.0015 NA 0.00010 NA 0.0010 NA 0.00083 NA NA NA NA NA BC 4 8 0.0051 NA 0.00061 NA 0.0070 NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA 0.00012 NA BC 5 8 NA NA NA NA NA NA NA NA NA NA NA NA BCHF 3 0.0056 NA NA 0.033 0.0049 0.012 0.029 0.0065 0.0012 0.019 0.0069 NA BCH 2 2 0.014 NA 0.0026 NA 0.0023 NA 0.0014 0.00086 0.000020 0.000030 NA NA BCH 3 0.00057 NA 0.12 NA NA 0.00073 NA NA 0.0082 NA NA NA Chamber Cleaning In situ plasma cleaning 1-U i NA NA NA NA NA NA NA 0.20 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.037 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA Remote plasma cleaning 1-U i NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.038 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA BCHF 3 NA NA NA NA NA NA NA 0.000059 NA NA NA NA BCH 2 2 NA NA NA NA NA NA NA 0.0016 NA NA NA NA BCH 3 NA NA NA NA NA NA NA 0.0028 NA NA NA NA In situ thermal cleaning 1-U i NA NA NA NA NA NA NA 0.28 NA NA NA NA BCF 4 NA NA NA NA NA NA NA 0.010 NA NA NA NA BC 2 6 NA NA NA NA NA NA NA NA NA NA NA NA BC 3 8 NA NA NA NA NA NA NA NA NA NA NA NA [89 FR 31923, Apr. 25, 2024] Table I-21 to Subpart I of Part 98—Examples of Fluorinated GHGs Used by the Electronics Industry Table I-21 to Subpart I of Part 98—Examples of Fluorinated GHGs Used by the Electronics Industry Product type Fluorinated GHGs used during manufacture Electronics CF 4 2 6 3 8 4 8 4 8 4 6 5 8 3 2 2 3 6 3 3 2 2 3 n 2n+2 n 2n+1 m 2m+1 n 2n n 2n+1 3N [89 FR 31924, Apr. 25, 2024.] Appendix A to Subpart I of Part 98—Alternative Procedures for Measuring Point-of-Use Abatement Device Destruction or Removal Efficiency If you are measuring destruction or removal efficiency of a point-of-use abatement device according to EPA 430-R-10-003 (incorporated by reference, see § 98.7) as specified in § 98.94(f)(4), you may follow the alternative procedures specified in paragraphs (a) through (c) of this appendix. (a) In place of the Quadrupole Mass Spectrometry protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you must conduct mass spectrometry testing in accordance with the provisions in paragraph (a)(1) through (a)(15) of this appendix. (1) Detection limits. (2) Sampling location. (3) Sampling conditions. 4 2 6 3 8 3 3 6 (4) Mass spectrometer parameters. The specific mass spectrometer operating conditions such as electron energy, secondary electron multiplier voltage, emission current, and ion focusing voltage must be selected according to the specifications provided by the mass spectrometer manufacturer, the mass spectrometer system manual, basic mass spectrometer textbook, or other such sources. The mass spectrometer responses to each of the target analytes must all be calibrated under the same mass spectrometer operating conditions. (5) Flow rates. (6) Sample frequency. (7) Dynamic dilution calibration parameters. 2 2 (8) Mass location calibration. (9) Quadrupole mass spectrometer response calibration. (10) Calibration frequency. (11) Calibration range. (12) Operating procedures. (i) You must perform a qualitative mass calibration by running a standard (or by flowing chamber gases under non-process conditions) containing stable components such as Ar, Kr, and Xe that provide predominant signals at m/e values distributed throughout the mass range to be used. You must adjust the quadrupole mass filter as needed to align with the inert gas fragments. (ii) You must quantitatively calibrate the quadrupole mass spectrometer for each analyte of interest. The analyte concentrations during calibration must include the expected concentrations in the process effluent. The calibration must be performed under the same operating conditions, such as inlet pressure, as when sampling process exhaust. If the calibration inlet pressure differs from the sampling inlet pressure then the relationship between inlet pressure and quadrupole mass spectrometer signal response must be empirically determined and applied to correct for any differences between calibration and process emissions monitoring data. (iii) To determine the response time of the instrument to changes in a process, a process gas such as C 2 6 (iv) You must sample the process effluent through the quadrupole mass spectrometer and acquire data for the required amount of time to track the process, as determined in paragraph (a)(12)(iii) of this appendix. You must set the sample frequency to monitor the changes in the process as specified in paragraph (a)(6) of this appendix. You must repeat this for at least five substrates on the same process and calculate the average and standard deviation of the analyte concentration. (v) You must repeat the quantitative calibration at the conclusion of sampling to identify any drifts in quadrupole mass spectrometer sensitivity. If drift is observed, you must use an internal standard to correct for changes in sensitivity. (13) Sample analysis. (14) Deconvolution of interfering peaks. (15) Calculations. 2 (b) In place of the Fourier Transform Infrared Spectroscopy protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may conduct Fourier Transform Infrared Spectroscopy testing in accordance with the provisions in paragraph (b)(1) through (17) of this appendix, including the laboratory study phase described in paragraphs (b)(1) through (7), and the field study phase described in paragraphs (b)(8) through (17) of this appendix. (1) Conformance with provisions associated with the Calibration Transfer Standard. (2) Defining spectroscopic conditions. (3) Criteria for reference spectral libraries. (4) Spectra without reference libraries. (i) Reference spectra at the same absorbance level (to within 10 percent) of independently prepared samples must be recorded. The reference samples must be prepared from neat forms of the analyte or from gas standards of the highest quality commonly available from commercial sources. Either barometric or volumetric methods may be used to dilute the reference samples to the required concentrations, and the equipment used must be independently calibrated to ensure suitable accuracy. Dynamic and static reference sample preparation methods are acceptable, but dynamic preparations must be used for reactive analytes. Any well characterized absorption pathlength may be employed in recording reference spectra, but the temperature and pressure of the reference samples should match as closely as possible those of the proposed spectroscopic conditions. (ii) If a mercury cadmium telluride or other potentially non-linear detector (i.e., a detector whose response vs. total infrared power is not a linear function over the range of responses employed) is used for recording the reference spectra, you must correct for the effects of this type of response on the resulting concentration values. As needed, spectra of a calibration transfer standard must be recorded with the laboratory spectrometer system to verify the absorption pathlength and other aspects of the system performance. All reference spectral data must be recorded in interferometric form and stored digitally. (5) Sampling system preparation. (6) Preliminary analytical routines. (7) Documentation. (8) Spectroscopic system performance. (9) System installation. (10) Pre-Test calibration. (11) Deriving the calibration transfer standard gas from tool chamber gases. (12) Reactivity and response time checks. (13) Analyte spiking. Where: AOITheoretical = Theoretical analyte of interest concentration (parts per million (ppm)). Tracersample = Tracer concentration (ppm) as seen by the Fourier Transform Infrared Spectrometer during spiking. Tracercylinder = The concentration (ppm) of tracer recorded during direct injection of the cylinder to the Fourier Transform Infrared Spectrometer cell. AOIcylinder = The supplier-certified concentration (ppm) of the analyte of interest gas standard. AOInative = The native AOI concentration (ppm) of the effluent during stable conditions. (14) Post-test calibration. (15) Amendment of analytical routines. (16) Documentation. (17) Method application. (i) The sampling lines employed should be as short as practically possible and not longer than those used in the field study. (ii) Analyte spiking and reactivity checks are required after the installation of or major repair to the sampling system or major change in sample matrix. In these cases, perform three spiked/unspiked samples with calibration transfer standard or a surrogate analyte on a daily basis if time permits and gas standards are easy to obtain and get on-site. (iii) Sampling and other operational data must be recorded and documented as during the field study, but only the interferometric data needed to sufficiently reproduce actual test and spiking data must be stored permanently. The format of this data does not need to be interferograms but may be absorbance spectra or single beams. (c) When using the flow and dilution measurement protocol specified in section 2.2.6 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may determine point-of-use abatement device total volume flow with the modifications specified in paragraphs (c)(1) through (3) of this appendix. (1) You may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device at a location in the exhaust of the point-of-use abatement device. For abatement systems operating in a mode where specific F-GHG are not readily abated, you may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device prior to the point-of-use abatement system; in this case, the tracer must be more difficult to destroy than the target compounds being measured based on the thermal stability of the tracer and target. (2) You may select a location for downstream non-reactive, non-native gas analysis that complies with the requirements in this paragraph (c)(2) of this appendix. The sampling location should be traversed with the sampling probe measuring the non-reactive, non-native gas concentrations to ensure homogeneity of the non-reactive gas and point-of-use abatement device effluent (i.e., stratification test). To test for stratification, measure the non-reactive, non-native gas concentrations at three points on a line passing through the centroidal area. Space the three points at 16.7, 50.0, and 83.3 percent of the measurement line. Sample for a minimum of twice the system response time, determined according to paragraph (c)(3) of this appendix, at each traverse point. Calculate the individual point and mean non-reactive, non-native gas concentrations. If the non-reactive, non-native gas concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±5.0 percent of the mean concentration, the gas stream is considered unstratified and you may collect samples from a single point that most closely matches the mean. If the 5.0 percent criterion is not met, but the concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±10.0 percent of the mean, you may take samples from two points and use the average of the two measurements. Space the two points at 16.7, 50.0, or 83.3 percent of the measurement line. If the concentration at each traverse point differs from the mean concentration for all traverse points by more than ±10.0 percent of the mean but less than 20.0 percent, take samples from three points at 16.7, 50.0, and 83.3 percent of the measurement line and use the average of the three measurements. If the gas stream is found to be stratified because the 20.0 percent criterion for a 3-point test is not met, locate and sample the non-reactive, non-native gas from traverse points for the test in accordance with Sections 11.2 and 11.3 of EPA Method 1 in 40 CFR part 60, Appendix A-1. A minimum of 40 non-reactive gas concentration measurements will be collected at three to five different injected non-reactive gas flow rates for determination of point-of-use abatement device effluent flow. The total volume flow of the point-of-use abatement device exhaust will be calculated consistent with the EPA 430-R-10-003 (incorporated by reference, see § 98.7) Equations 1 through 7. (3) You must determine the measurement system response time according to paragraphs (c)(3)(i) through (iii) of this appendix. (i) Before sampling begins, introduce ambient air at the probe upstream of all sample condition components in system calibration mode. Record the time it takes for the measured concentration of a selected compound (for example, carbon dioxide) to reach steady state. (ii) Introduce nitrogen in the system calibration mode and record the time required for the concentration of the selected compound to reach steady state. (iii) Observe the time required to achieve 95 percent of a stable response for both nitrogen and ambient air. The longer interval is the measurement system response time. [78 FR 68234, Nov. 13, 2013] Subpart J [Reserved] Subpart K—Ferroalloy Production § 98.110 Definition of the source category. 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. § 98.111 Reporting threshold. 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). § 98.112 GHGs to report. You must report: (a) Process CO 2 4 (b) CO 2 4 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010] § 98.113 Calculating GHG emissions. You must calculate and report the annual process CO 2 4 4 (a) Calculate and report under this subpart the process CO 2 (b) Calculate and report under this subpart the annual process CO 2 (1) Calculate and report under this subpart the annual process CO 2 (2) Calculate and report under this subpart the annual process CO 2 (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 Where: E CO2 2 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion factor to convert tons to metric tons. M reducing agent i i C reducing agent i i M electrode m m C electrode m m M ore h h C ore h h M flux j j C flux j j M product k k C product k k. M non-product outgoing l l C non-product outgoing l l (ii) Determine the combined annual process CO 2 Where: CO 2 2 E CO2 k 2 k 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 (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 (1) For each EAF, determine the annual CH 4 Where: E CH4 4 M product i i 2/2205 = Conversion factor to convert kg CH 4 4 EF product i 4 i 4 i (2) Determine the combined process CH 4 Where: CH 4 4 E CH4 j 4 j j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66461, Oct. 28, 2010; 78 FR 71954, Nov. 29, 2013] § 98.114 Monitoring and QA/QC requirements. If you determine annual process CO 2 (a) Determine the annual mass for each material used for the calculations of annual process CO 2 (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 (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.115 Procedures for estimating missing data. 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 (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 § 98.116 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable: (a) Annual facility ferroalloy product production capacity (tons). (b) If a CEMS is used to measure CO 2 (c) Total number of EAFs at facility used for production of ferroalloy products. (d) If a CEMS is used to measure CO 2 (1) Annual process CO 2 (2) Annual process CH 4 (3) Identification number of each EAF. (e) If a CEMS is not used to measure CO 2 2 (1) Annual process CO 2 (2) Annual process CH 4 (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 e.g., (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. [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] § 98.117 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each EAF, as applicable. (a) If a CEMS is used to measure CO 2 (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 (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 (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 (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 4 (e) Verification software records. (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 4 [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63785, Oct. 24, 2014] § 98.118 Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table K-1 to Subpart K of Part 98—Electric Arc Furnace (EAF) CH 4 Alloy product produced in EAF CH 4 4 EAF Operation Batch-charging Sprinkle-charging a Sprinkle-charging and b Silicon metal 1.5 1.2 0.7 Ferrosilicon 90% 1.4 1.1 0.6 Ferrosilicon 75% 1.3 1.0 0.5 Ferrosilicon 65% 1.3 1.0 0.5 a b Subpart L—Fluorinated Gas Production Source: 75 FR 74831, Dec. 1, 2010, unless otherwise noted. § 98.120 Definition of the source category. (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). § 98.121 Reporting threshold. 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 § 98.122 GHGs to report. (a) You must report CO 2 4 2 (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. 2 (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. 2 2 (e) Emissions from production and transformation processes, facility level, one product only. 2 (f) Emissions from destruction processes and venting of containers. (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. [75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014 § 98.123 Calculating GHG emissions. 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., (a) [Reserved] (b) Mass balance method. (c) Emission factor and emission calculation factor methods. (1) Preliminary estimate of emissions by process vent. 2 (i) Engineering calculations. (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 4 ( 1 3 ( 2 10 ( 3 ( i system ( ii i ( iii j ( iv Fluorinated GHG ( 4 ( i Fluorinated GHG ( ii ( iii ( iv ( v (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. (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. (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. (v) GWPs. 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 (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 (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. (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 2 (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 C PV MW = Molecular weight of fluorinated GHG f (g/g-mole). Q PV 3 SV = Standard molar volume of gas (0.0240 m 3 1/10 3 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 E PV Activity EmissionTest 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 EF PV-C Activity C ECF PV-U Activity U (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 EF PV-U Activity U Activity C DE = Demonstrated destruction efficiency of the destruction device (weight fraction). (viii) Adjusted process-vent-specific emission factors for other operating scenarios. 2 where: EF PVadj ECF UT ECF T EF PV (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 E PV 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. (i) You must calculate uncontrolled emissions of fluorinated GHG by individual process vent, E PV (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 E PV Activity Representative (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 ECF PV 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 ECF PV Activity U Activity C 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 E PV 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). (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. (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. (iii) Use of Other Approaches in EPA Protocol for Equipment Leak Emission Estimates in conjunction with site-specific leak monitoring methods. (iv) Use of site-specific leak monitoring methods. (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 (e) Calculate total fluorinated GHG emissions for each process and for production or transformation processes at the facility. where: E i E Pfi E ELfi (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 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”. where: E D RE D DE = Destruction efficiency of the destruction device (fraction). (g) Emissions from venting of residual fluorinated GHGs in containers. (1) Measuring contents of each container. Where: E Cf H Bfj H Efj n = Number of vented containers for each fluorinated GHG f. (2) Developing and applying heel factors. (i) Sample size. (ii) Measurement of residual gas. Where: m R 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 T = Absolute temperature (K). 10 6 6 (iii) Heel factor calculation. fj (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 h fj N fj F fj n = Number of combinations of container sizes and types for fluorinated GHG f. (h) Effective destruction efficiency for each process. Where: DE Effective E PVf GWP f ECF PV-Uf e.g., PV EF PV-Uf e.g., PV-U Activity U i.e., Activity C i.e., 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. [75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73785, Dec. 11, 2014] § 98.124 Monitoring and QA/QC requirements. (a) Initial scoping speciation to identify fluorinated GHGs. (1) Procedure. (2) Previous measurements. (b) Mass balance monitoring. (c) Emission factor testing. (1) Process vent testing. (2) Number of runs. 2 (3) Process activity measurements. (4) Sample each process. (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. e.g., (6) Emissions testing frequency. (i) 10-year revision. (ii) Operating scenario change that affects the emission factor. (7) Subsequent measurements. 2 2 (8) Previous measurements. (d) Emission calculation factor monitoring. (1) Operating scenario. (2) Process activity measurements. (3) Emission calculation results. (4) Operating scenario change that affects the emission calculation factor. (5) Previous calculations. (e) Emission and stream testing, including analytical methods. (1) Sampling and mass measurement for emission testing. (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. (3) Documentation in GHG Monitoring Plan. (f) Emission monitoring for pieces of equipment. (1) Site-specific leak monitoring approach. (2) EPA Method 21 monitoring. (3) Frequency of measurement and sampling. (g) Destruction device performance testing. (1) Destruction efficiency testing. (i) If perfluoromethane (CF 4 4 4 (ii) If sulfur hexafluoride (SF 6 6 4 6 (iii) If saturated perfluorocarbons other than CF 4 6 (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. (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. (3) Previous testing (4) Hazardous Waste Combustor testing. 4 6 4 (h) Mass of previously produced fluorinated GHGs fed into destruction device. (i) Emissions due to malfunctions of destruction device. (j) Emissions due to process startup, shutdown, or malfunctions. (k) Monitoring for venting residual fluorinated GHG in containers. (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. (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. (i) Timing of request. (ii) Content of request. (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. (i) Timing of request. (ii) Content of request. (iii) Reporting of 2011 emissions using scoping speciations, emission factors, and emission characterizations developed after February 29, 2012. (4) Requests for extension of the use of best available monitoring methods to estimate emissions that occur after 2011. (i) Timing of request. (ii) Content of request. (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. (5) Approval criteria. [75 FR 74831, Dec. 1, 2010, as amended at 79 FR 73787, Dec. 11, 2014] § 98.125 Procedures for estimating missing data. (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. § 98.126 Data reporting requirements. (a) All facilities. (1) Frequency of reporting under paragraph (a) of this section. (2) Generically-identified process. (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., (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. 2 (4) Emissions from production and transformation processes, facility level, multiple products. (i) For each fluorinated GHG with emissions of 1,000 metric tons of CO 2 (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 (5) Emissions from production and transformation processes, facility level, one product only. 2 (6) Effective destruction efficiency. effective 2 (b) Reporting for mass balance method for reporting years 2011, 2012, 2013, and 2014. (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 (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. (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 (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 (d) Reporting for missing data. (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. (f) Reporting of destruction device testing. (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. (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. (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. (j) Special provisions for reporting years 2011, 2012, and 2013 only. (1) Timing. (2) Excess emissions. 2 (3) Calculation and reporting of CO 2 e. 2 2 3 (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 (iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO 2 (iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO 2 (k) Submission of complete reporting year 2011, 2012, and 2013 GHG reports. 2 [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] § 98.127 Records that must be retained. 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. (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 2 (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 (b) Scoping speciation. (c) Mass balance method. (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 k (d) Emission factor and emission calculation factor method. (1) Identify all continuous process vents with emissions of fluorinated GHGs that are less than 10,000 metric tons CO 2 2 (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. (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 (9) Name of all applicable Federal or State regulations that may apply to the destruction process. (f) Equipment leak records. (g) Container heel records. (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. (i) All facilities. (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 1 3 (l) Verification software records. (1) The identity of the process vent ( e.g., (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., C, U (4) The quantities of the process activity used to estimate controlled and uncontrolled emissions, respectively, for the process vent, Activity, Activity U, C e.g. (5) The site-specific, process-vent-specific emission factor, EF PV-C, (6) The site-specific, process-vent-specific emission calculation factor, ECF PV-U, (7) The site-specific, process-vent-specific emission factor(s), EF PV-U, (8) The site-specific, process-vent-specific emission calculation factor for the process vent, ECF PV (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 (11) The mass of the fluorinated GHG previously produced and fed into the destruction device, RE D (12) If applicable, the heel factor, h fj (13) If applicable, the number of containers of size and type j returned to the fluorinated gas production facility, N fj (14) If applicable, the full capacity of containers of size and type j containing fluorinated GHG f, F fj (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 i [75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 FR 73788, Dec. 11, 2014] § 98.128 Definitions. 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 batch operation Batch emission episode By-product Completely destroyed Completely recaptured Continuous process or operation Destruction device Destruction process Difficult-to-monitor Dual mechanical seal pump dual mechanical seal agitator (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 Fluorinated gas Fluorinated gas product Fully fluorinated GHGs 6 3 5 3 Generically-identified process (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 In gas and vapor service In heavy liquid service In light liquid service (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. Note to definition of “in light liquid service”: Vapor pressures may be determined by standard reference texts or ASTM D-2879, (incorporated by reference, see § 98.7). In vacuum service Isolated intermediate Major fluorinated GHG constituent No external shaft pump No external shaft agitator 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 Process condenser Process vent Typical batch Uncontrolled fluorinated GHG emissions Unsafe-to-monitor [75 FR 74831, Dec. 1, 2010, as amended at 77 FR 51490, Aug. 24, 2012; 79 FR 73789, Dec. 11, 2014] Table L-1 to Subpart L of Part 98—Ranges of Effective Destruction Efficiency Range of Reductions ≥99%. ≥95% to <99%. ≥75% to <95%. ≥0% to <75%. [79 FR 73789, Dec. 11, 2014] Appendix A to Subpart L of Part 98—Mass Balance Method for Fluorinated Gas Production 1. Mass Balance Method for § 98.123(b). (b) Mass balance method. 2 2 (1) Error calculation. e.g., (i) Where the measured quantity is a mass, the error in the mass must be equated to the accuracy or precision (whichever is larger) of the flowmeter, scale, or combination of volumetric and density measurements at the flow rate or mass measured. (ii) Where the measured quantity is a concentration of a stream component, the error of the concentration must be equated to the accuracy or precision (whichever is larger) with which you estimate the mean concentration of that stream component, accounting for the variability of the process, the frequency of the measurements, and the accuracy or precision (whichever is larger) of the analytical technique used to measure the concentration at the concentration measured. If the variability of process measurements is used to estimate the error, this variability shall be assumed to account both for the variability of the process and the precision of the analytical technique. Use standard statistical techniques such as the student's t distribution to estimate the error of the mean of the concentration measurements as a function of process variability and frequency of measurement. (iii) Equation L-1 of this section provides the general formula for calculating the absolute errors of sums and differences where the sum, S, is the summation of variables measured, a, b, c, etc. ( e.g., Where: e SA e a e b e c (iv) Equation L-2 of this section provides the general formula for calculating the relative errors of sums and differences: Where: e SR e SA a + b + c = Sum of the variables measured. (v) Equation L-3 of this section provides the general formula for calculating the absolute errors of products ( e.g., e.g., Where: e PA e a e b e c (vi) Equation L-4 of this section provides the general formula for calculating the relative errors of products: Where: e PR e PA a*b*c = Product of the variables measured. (vii) Calculate the absolute error of the emissions estimate in terms of CO 2 2 (viii) To estimate the annual CO 2 d k 2 (2) The total mass of each fluorinated GHG emitted annually from each fluorinated gas production and each fluorinated GHG transformation process must be estimated by using Equation L-5 of this section. Where: E FGHGf E Rp-FGHGf E Pp-FGHGf E Bp-FGHGf n = Number of concentration and flow measurement periods for the year. (3) The total mass of fluorine emitted from process i over the period p must be estimated at least monthly by calculating the difference between the total mass of fluorine in the reactant(s) (or inputs, for processes that do not involve a chemical reaction) and the total mass of fluorine in the product (or outputs, for processes that do not involve a chemical reaction), accounting for the total mass of fluorine in any destroyed or recaptured streams that contain reactants, products, or by-products (or inputs or outputs). This calculation must be performed using Equation L-6 of this section. An element other than fluorine may be used in the mass-balance equation, provided the element occurs in all of the fluorinated GHGs fed into or generated by the process. In this case, the mass fractions of the element in the reactants, products, and by-products must be calculated as appropriate for that element. Where: E F R d P = Total mass of the fluorine-containing product produced by process i over the period p (metric tons). MFF Rd MFF P F D v = Number of fluorine-containing reactants fed into process i. (4) The mass of total fluorine in destroyed or recaptured streams containing fluorine-containing reactants, products, and by-products must be estimated at least monthly using Equation L-7 of this section unless you use the alternative approach provided in paragraph (b)(15) of this section. Where: F D P j B kj B kl R dj MFF Rd MFF P MFF Bk q = Number of streams destroyed in process i. x = Number of streams recaptured in process i. u = Number of fluorine-containing by-products generated in process i. v = Number of fluorine-containing reactants fed into process i. (5) The mass of each fluorinated GHG removed from process i in stream j and destroyed over the period p ( i.e., j kj dj Where: M FGHGfj j kj dj DE FGHGf C FGHGfj F-GHGfj S j (6) The mass of each fluorine-containing compound that is not a fluorinated GHG and that is removed from process i in stream j and destroyed over the period p ( i.e., j kj dj Where: M FCgj j kj dj c FCgj FCgj S j (7) The mass of fluorine-containing by-product k removed from process i in stream l and recaptured over the period p must be estimated using Equation L-10 of this section: Where: B kl c Bkl Bkl S l (8) To estimate the terms FER d k F d k D e.g., (i) If the calculations under paragraph (b)(1)(viii) of this section, or any subsequent measurements and calculations under this subpart, indicate that the process emits 25,000 metric tons CO 2 2 (ii) For other vents, including vents from processes that emit less than 25,000 metric tons CO 2 (iii) For fluorine emissions that are not accounted for by vent estimates, you must characterize emissions as specified in § 98.124(b)(6). (9) The total mass of fluorine-containing reactant d emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing reactants using Equation L-11 of this section. If the fluorine-containing reactant d is a non-GHG, you may assume that FER d Where: E R-ip FER d E F FEP = The fraction of the mass emitted that consists of the fluorine-containing product. FEB k MFF Rd MFF P MFF Bk u = Number of fluorine-containing by-products generated in process i. v = Number of fluorine-containing reactants fed into process i. (10) The total mass of fluorine-containing product emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing products using Equation L-12 of this section. If the fluorine-containing product is a non-GHG, you may assume that FEP is zero. Where: E P-ip FEP = The fraction of the mass emitted that consists of the fluorine-containing product. E F FER d FEB k MFF Rd MFF P MFF Bk u = Number of fluorine-containing by-products generated in process i. v = Number of fluorine-containing reactants fed into process i. (11) The total mass of fluorine-containing by-product k emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing by-products using Equation L-13 of this section. If fluorine-containing by-product k is a non-GHG, you may assume that FEB k Where: E Bk-ip FEB k FER d FEP = The fraction of the mass emitted that consists of the fluorine-containing product. E F MFF Rd MFF P MFF Bk u = Number of fluorine-containing by-products generated in process i. v = Number of fluorine-containing reactants fed into process i. (12) The mass fraction of fluorine in reactant d must be estimated using Equation L-14 of this section: Where: MFF Rd MF Rd AW F MW Rd (13) The mass fraction of fluorine in the product must be estimated using Equation L-15 of this section: Where: MFF P MF P AW F MW P (14) The mass fraction of fluorine in by-product k must be estimated using Equation L-16 of this section: Where: MFF Bk MF Bk AW F MW Bk (15) Alternative for determining the mass of fluorine destroyed or recaptured. As an alternative to using Equation L-7 of this section as provided in paragraph (b)(4) of this section, you may estimate at least monthly the total mass of fluorine in destroyed or recaptured streams containing fluorine-containing compounds (including all fluorine-containing reactants, products, and byproducts) using Equation L-17 of this section. Where: F D DE avgj c TFj TFj S j c TFl Bkl S l q = Number of streams destroyed in process i. x = Number of streams recaptured in process i. (16) Weighted average destruction efficiency. For purposes of Equation L-17 of this section, calculate the weighted average destruction efficiency applicable to a destroyed stream using Equation L-18 of this section. Where: DE avgj DE FGHGf c FGHGfj F-GHGfj c FCgj FCgj S j MFF FGHGf MFF FCg w = Number of fluorinated GHGs in destroyed stream j. y = Number of non-GHG fluorine-containing compounds in destroyed stream j. 2. Mass Balance Method for § 98.124(b). (b) Mass balance monitoring. (1) Mass measurements. (i) Total mass of each fluorine-containing product produced. Account for any used fluorine-containing product added into the production process upstream of the output measurement as directed at §§ 98.413(b) and 98.414(b). For each product, the mass produced used for the mass-balance calculation must be the same as the mass produced that is reported under subpart OO of this part, where applicable. (ii) Total mass of each fluorine-containing reactant fed into the process. (iii) The mass removed from the process in each stream fed into the destruction device. (iv) The mass removed from the process in each recaptured stream. (2) Concentration measurements for use with § 98.123(b)(4). e.g., e.g., (i) The concentration (mass fraction) of the fluorine-containing product in each stream that is fed into the destruction device. (ii) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is fed into the destruction device. (iii) The concentration (mass fraction) of each fluorine-containing reactant in each stream that is fed into the destruction device. (iv) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is recaptured (c Bkl (3) Concentration measurements for use with § 98.123(b)(15). e.g., e.g., (i) The concentration (mass fraction) of total fluorine in each stream that is fed into the destruction device. (ii) The concentration (mass fraction) of total fluorine in each stream that is recaptured. (4) Emissions characterization: process vents emitting 25,000 metric tons CO 2 e or more. 2 (i) Uncontrolled emissions. (ii) Controlled emissions using § 98.123(b)(15). (iii) Controlled emissions using § 98.123(b)(4). (iv) Emissions characterization frequency. (A) 10-year revision. (B) Operating scenario change that affects the emission characterization. (v) Subsequent measurements. 2 2 (5) Emissions characterization: Process vents emitting less than 25,000 metric tons CO 2 e. 2 (i) Uncontrolled emissions. (ii) Controlled emissions using § 98.123(b)(15). (iii) Controlled emissions using § 98.123(b)(4). (6) Emissions characterization: Emissions not accounted for by process vent estimates. (7) Impurities in reactants. (8) Alternative to error calculation. (i) Mass measurements. (ii) Concentration measurements. (iii) Measurement and calculation frequency. (iv) Fluorinated-GHG throughput limit. 2 2 2 [79 FR 73789, Dec. 11, 2014] Subpart M [Reserved] Subpart N—Glass Production § 98.140 Definition of the source category. (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. § 98.141 Reporting threshold. 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). § 98.142 GHGs to report. You must report: (a) CO 2 (b) CO 2 (c) CH 4 2 (d) CO 2 4 2 § 98.143 Calculating GHG emissions. You must calculate and report the annual process CO 2 (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 2 (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 (1) Calculate and report under this subpart the combined process and combustion CO 2 2 (2) Calculate and report the process and combustion CO 2 (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 Where: E CO2 2 n = Number of carbonate-based raw materials charged to furnace. MF i M i 2000/2205 = Conversion factor to convert tons to metric tons. EF i 2 F i (v) You must calculate the total process CO 2 Where: CO 2 2 E CO2i 2 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 (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 [75 FR 74831, Dec. 1, 2010, as amended at 78 FR 71954, Nov. 29, 2013] § 98.144 Monitoring and QA/QC requirements. (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., [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] § 98.145 Procedures for estimating missing data. 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. § 98.146 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable. (a) If a CEMS is used to measure CO 2 (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 2 (1) Annual process emissions of CO 2 (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). [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] § 98.147 Records that must be retained. 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 (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. (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). [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] § 98.148 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table N-1 to Subpart N of Part 98—CO 2 Carbonate-based CO 2 a Limestone—CaCO 3 0.440 Dolomite—CaMg(CO 3 2 0.477 Sodium carbonate/soda ash—Na 2 3 0.415 Barium carbonate—BaCO 3 0.223 Potassium carbonate—K 2 3 0.318 Lithium carbonate (Li 2 3 0.596 Strontium carbonate (SrCO 3 0.298 a 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462 , Oct. 28, 2010] Subpart O—HCFC-22 Production and HFC-23 Destruction § 98.150 Definition of the source category. 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 3 (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. § 98.151 Reporting threshold. 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). § 98.152 GHGs to report. (a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 (b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes. § 98.153 Calculating GHG emissions. (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 c 23 F p p = Period over which mass flows and concentrations are measured. n = Number of concentration and flow measurement periods for the year. 10 −3 (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 c 23 c 22 P 22 p = Period over which masses and concentrations are measured. n = Number of concentration and mass measurement periods for the year. 10 −3 (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 O 22 U 22 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 G 23 S 23 OD 23 D 23 I 23 (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 E L E PV E D (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 c 23 F Gt N Gt F Lt N Lt 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 (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 ER T PR p PR T l p 10 −3 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 F D D 23 (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 F D DE = Destruction Efficiency of the destruction device (fraction). [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013] § 98.154 Monitoring and QA/QC requirements. 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. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66462, Oct. 28, 2010; 78 FR 71955, Nov. 29, 2013] § 98.155 Procedures for estimating missing data. (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. § 98.156 Data reporting requirements. (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. [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] § 98.157 Records that must be retained. (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. (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)). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 79 FR 63786, Oct. 24, 2014] § 98.158 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table O-1 to Subpart O of Part 98—Emission Factors for Equipment Leaks Equipment type Service Emission factor ≥10,000 ppmv <10,000 ppmv Valves Gas 0.0782 0.000131 Valves Light liquid 0.0892 0.000165 Pump seals Light liquid 0.243 0.00187 Compressor seals Gas 1.608 0.0894 Pressure relief valves Gas 1.691 0.0447 Connectors All 0.113 0.0000810 Open-ended lines All 0.01195 0.00150 Subpart P—Hydrogen Production § 98.160 Definition of the source category. (a) A hydrogen production source category consists of facilities that produce hydrogen gas as a product. (b) This source category comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of feedstocks except the processes listed in paragraph (b)(1) or (2) of this section. (1) Any process unit for which emissions are reported under another subpart of this part. This includes, but is not necessarily limited to: (i) Ammonia production units for which emissions are reported under subpart G. (ii) Catalytic reforming units at petroleum refineries that transform 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. [89 FR 31925, Apr. 25, 2024] § 98.161 Reporting threshold. 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). § 98.162 GHGs to report. You must report: (a) CO 2 (b) [Reserved] (c) CO 2 4 2 (d) For CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 89 FR 31926, Apr. 25, 2024] § 98.163 Calculating GHG emissions. You must calculate and report the annual CO 2 (a) Continuous Emissions Monitoring Systems (CEMS). 2 (b) Fuel and feedstock material balance approach. Calculate and report CO 2 (1) Gaseous fuel and feedstock. 2 Where: CO 2 2 Fdstk n CC n MW n n 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 (2) Liquid fuel and feedstock. 2 Where: CO 2 2 Fdstk n CC n k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 0.001 = Conversion factor from kg to metric tons. (3) Solid fuel and feedstock. 2 Where: CO 2 2 Fdstk n CC n k = Months in the year. 44/12 = Ratio of molecular weights, CO 2 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 i.e. 2 [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] § 98.164 Monitoring and QA/QC requirements. The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraph (a) or (b) of this section, as appropriate for each process unit, except as provided in paragraph (c) of this section: (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., e.g., (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., (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., (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 (ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see (iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see (iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see (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 (vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see (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 (viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference, see (ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see (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 (xi) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (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 (xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see (xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see (xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see (xvii) ISO 3170: Petroleum Liquids—Manual sampling—Third Edition (incorporated by reference, see (xviii) ISO 3171: Petroleum Liquids—Automatic pipeline sampling—Second Edition (incorporated by reference, see (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., (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., (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. [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] § 98.165 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (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. § 98.166 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each hydrogen production process unit: (a) The unit identification number. (b) If a CEMS is used to measure CO 2 2 (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 (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 (7) Annual quantity of carbon other than CO 2 (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., (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., (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., [89 FR 31927, Apr. 25, 2024] § 98.167 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each hydrogen production facility. (a) If a CEMS is used to measure CO 2 2 (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). [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] § 98.168 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart Q—Iron and Steel Production § 98.170 Definition of the source category. 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. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71955, Nov. 29, 2013] § 98.171 Reporting threshold. 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). § 98.172 GHGs to report. (a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 (b) You must report CO 2 2 4 2 (c) You must report process CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010] § 98.173 Calculating GHG emissions. You must calculate and report the annual process CO 2 2 (a) Calculate and report under this subpart the process CO 2 (b) Calculate and report under this subpart the process CO 2 (1) Carbon mass balance method. 2 2 (i) For taconite indurating furnaces, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (F s (C sf (F g (C gf 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 (C lf (O) = Annual mass of greenball (taconite) pellets fed to the furnace (metric tons). (C 0 (P) = Annual mass of fired pellets produced by the furnace (metric tons). (C p (R) = Annual mass of air pollution control residue collected (metric tons). (C R (ii) For basic oxygen process furnaces, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (Iron) = Annual mass of molten iron charged to the furnace (metric tons). (C Iron (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap (Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons). (C Flux (Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel (Slag) = Annual mass of slag produced by the furnace (metric tons). (C Slag (R) = Annual mass of air pollution control residue collected (metric tons). (C R (iii) For non-recovery coke oven batteries, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (Coal) = Annual mass of coal charged to the battery (metric tons). (C Coal (Coke) = Annual mass of coke produced by the battery (metric tons). (C Coke (R) = Annual mass of air pollution control residue collected (metric tons). (C R (iv) For sinter processes, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (F g (C gf 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 (Sinter) = Annual mass of sinter produced (metric tons). (C Sinter (R) = Annual mass of air pollution control residue collected (metric tons). (C R (v) For EAFs, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons). (C Iron (Scrap) = Annual mass of ferrous scrap charged to the furnace (metric tons). (C Scrap (Flux) = Annual mass of flux materials ( e.g., (C Flux (Electrode) = Annual mass of carbon electrode consumed (metric tons). (C Electrode (Carbon) = Annual mass of carbonaceous materials ( e.g., (C Carbon (Steel) = Annual mass of molten raw steel produced by the furnace (metric tons). (C Steel (F g (C gf (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 (R) = Annual mass of air pollution control residue collected (metric tons). (C R (vi) For decarburization vessels, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (Steel) = Annual mass of molten steel charged to the vessel (metric tons). (C Steelin (C Steelout (R) = Annual mass of air pollution control residue collected (metric tons). (C R (vii) For direct reduction furnaces, estimate CO 2 Where: CO 2 2 44/12 = Ratio of molecular weights, CO 2 (F g (C gf 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) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons). (C Carbon (Other) = Annual mass of other materials charged to the furnace (metric tons). (C Other (Iron) = Annual mass of iron produced (metric tons). (C Iron (NM) = Annual mass of non-metallic materials produced by the furnace (metric tons). (C NM (R) = Annual mass of air pollution control residue collected (metric tons). (C R (2) Site-specific emission factor method. 2 (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 2 Where: CO 2 2 5.18 × 10 −7 2 C CO2 2 2 Q = Hourly stack gas volumetric flow rate (scfh). %H 2 (iii) You must calculate a site-specific emission factor for the process in metric tons of CO 2 2 (iv) You must calculate CO 2 (c) You must determine emissions of CO 2 2 (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 [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] § 98.174 Monitoring and QA/QC requirements. (a) If you operate and maintain a CEMS that measures CO 2 (b) If you determine CO 2 (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 (ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (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 (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 (v) ASM CS-104 UNS No. G10460—Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference, see see see (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 (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 (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 (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. [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] § 98.175 Procedures for estimating missing data. 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. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013] § 98.176 Data reporting requirements. 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 (b) If a CEMS is used to measure CO 2 (c) If a CEMS is used to measure CO 2 (d) If a CEMS is not used to measure CO 2 (e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO 2 (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 (i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used in process units for which CO 2 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 g MW i 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 l F s,i s ρ l,i 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 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 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 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 C lf,i C sf 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 n = Number of non-fuel inputs to all process units as used in Equation Q-10. NFI i C NFIi 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 n = Number of products and byproducts from each process unit as used in Equation Q-11 of this section. Product i C p,i 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 (1) The measured average hourly CO 2 (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. [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] § 98.177 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (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. (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)). [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] § 98.178 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart R—Lead Production § 98.180 Definition of the source category. 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. § 98.181 Reporting threshold. 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). § 98.182 GHGs to report. You must report: (a) Process CO 2 (b) CO 2 (c) CH 4 2 (d) CO 2 4 2 § 98.183 Calculating GHG emissions. You must calculate and report the annual process CO 2 (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 2 (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 (1) Calculate and report under this subpart the combined process and combustion CO 2 2 (2) Calculate and report process and combustion CO 2 (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 Where: E CO2 2 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion factor to convert tons to metric tons. Ore = Annual mass of lead ore charged to the smelting furnace (tons). C Ore Scrap = Annual mass of lead scrap charged to the smelting furnace (tons). C Scrap Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged to the smelting furnace (tons). C Flux Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the smelting furnace (tons). C Carbon Other = Annual mass of any other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons). C Other (ii) Determine the combined annual process CO 2 Where: CO 2 2 E CO2 k 2 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 § 98.184 Monitoring and QA/QC requirements. If you determine process CO 2 (a) Determine the annual mass for each material used for the calculations of annual process CO 2 (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. § 98.185 Procedures for estimating missing data. 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 (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). § 98.186 Data reporting procedures. 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 (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 2 (1) Identification number of each smelting furnace. (2) Annual process CO 2 (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 (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. [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014] § 98.187 Records that must be retained. 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 (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 (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 (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 (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. (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). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014] § 98.188 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart S—Lime Manufacturing § 98.190 Definition of the source category. (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). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66464, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013] § 98.191 Reporting threshold. 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). § 98.192 GHGs to report. You must report: (a) CO 2 (b) CO 2 (c) N 2 4 (d) CO 2 2 4 (e) CO 2 2 § 98.193 Calculating GHG emissions. You must calculate and report the annual process CO 2 (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 2 (b) If CEMS are not required to be used to determine CO 2 2 (1) Calculate and report under this subpart the combined process and combustion CO 2 2 (2) Calculate and report process and combustion CO 2 (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 2 SR CaO 2 2 SR MgO 2 2 CaO i,n MgO i,n 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 2 SR CaO 2 2 SR MgO 2 2 CaO LKD,i,n MgO LKD,i,n 2000/2205 = Conversion factor for tons to metric tons. (iii) You must calculate the annual CO 2 Where: E waste,i 2 2 SR CaO 2 2 SR MgO 2 2 CaO waste,i MgO waste,i M waste,i 2000/2205 = Conversion factor for tons to metric tons. (iv) You must calculate annual CO 2 Where: E CO2 2 EF LIME,i,n 2 M LIME,i,n EF LKD,i,n 2 M LKD,i,n E waste,i 2 2 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 (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 2 EF LIME,i,n 2 n = Number of calendar months with calculated EF LIME,i,n (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 2 EF LKD,i,n 2 n = Number of calendar months with calculated EF LKD,i,n (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 CaO i,n n = Number of calendar months with calculated CaO ,i,n Where: MgO i,avg MgO i,n n = Number of calendar months with calculated MgO ,i,n Where: CaO LKD,i,avg CaO LKD,i,n n = Number of calendar months with calculated CaO LKD,i,n Where: MgO LKD,i,avg MgO LKD,i,n n = Number of calendar months with calculated MgO LKD,i,n [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] § 98.194 Monitoring and QA/QC requirements. (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 (2) The National Lime Association's CO 2 (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 see [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 78 FR 71958, Nov. 29, 2013] § 98.195 Procedures for estimating missing data. 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). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66465, Oct. 28, 2010; 78 FR 71959, Nov. 29, 2013] § 98.196 Data reporting requirements. 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 (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 (1) Annual CO 2 (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 e.g., 2 (i) The annual amount of CO 2 (ii) The method used to determine the amount of CO 2 (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. [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] § 98.197 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (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. (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). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014] § 98.198 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table S-1 to Subpart S of Part 98—Basic Parameters for the Calculation of Emission Factors for Lime Production Variable Stoichiometric ratio SR CaO 0.7848 SR MgO 1.0918 Subpart T—Magnesium Production Source: 75 FR 39761, July 12, 2010, unless otherwise noted. § 98.200 Definition of source category. 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. § 98.201 Reporting threshold. 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). § 98.202 GHGs to report. (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 2 4 § 98.203 Calculating GHG emissions. (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 I B,x I E,x A X D X 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 Q p 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 e.g., M B M E (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 § 98.204 Monitoring and QA/QC requirements. (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., (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., (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. § 98.205 Procedures for estimating missing data. (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 C GHG 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., § 98.206 Data reporting requirements. 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., (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., (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., (h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year. § 98.207 Records that must be retained. 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. § 98.208 Definitions. 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 2 2 Cover gas 6 Subpart U—Miscellaneous Uses of Carbonate § 98.210 Definition of the source category. (a) This source category includes any equipment that uses carbonates listed in Table U-1 in manufacturing processes that emit carbon dioxide. Table U-1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO 2 (b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, zinc, or ceramics. (c) This source category does not include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel Combustion Sources). [74 FR 56374, Oct. 30, 2009, as amended at 89 FR 31929, Apr. 25, 2024] § 98.211 Reporting threshold. You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in § 98.210 of this subpart and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.212 GHGs to report. You must report CO 2 § 98.213 Calculating GHG emissions. You must determine CO 2 (a) Calculate the process emissions of CO 2 Where: E CO2 2 M i EF i 2 F i n = Number of carbonate types. 2000/2205 = Conversion factor to convert tons to metric tons. (b) Calculate the process emissions of CO 2 Where: E CO2 2 M k EF k 2 M j EF j 2 m = Number of input carbonate types. n = Number of output carbonate types. § 98.214 Monitoring and QA/QC requirements. (a) The annual mass of carbonate consumed (for Equation U-1 of this subpart) or carbonate inputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders. (b) The annual mass of carbonate outputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders. (c) If you follow the procedures of § 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.). § 98.215 Procedures for estimating missing data. (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, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used for all such estimates. (b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the substitute data value must be the best available estimate based on the all available process data or data used for accounting purposes. § 98.216 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable. (a) Annual CO 2 (b) [Reserved] (c) Measurement method used to determine the mass of carbonate. (d) Method used to calculate emissions. (e) If you followed the calculation method of § 98.213(a), you must report the information in paragraphs (e)(1) through (3) of this section. (1)-(2) [Reserved] (3) If you determined the calcination fraction, indicate which standard method was used. (f) [Reserved] (g) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption, carbonate input or carbonate output (months). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014; 81 FR 89259, Dec. 9, 2016] § 98.217 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section: (a) Monthly carbonate consumption (by carbonate type in tons). (b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement devices. (c) Records of all analyses conducted to meet the requirements of this rule. (d) Records of all calculations conducted. (e) Verification software records. (1) Fraction calcination achieved for each particular carbonate type. As an alternative to measuring the calcination fraction, a value of 1.0 can be used (decimal fraction) (Equation U-1 of § 98.213). (2) Annual mass of each carbonate type consumed (tons) (Equation U-1). (3) Annual mass of each input carbonate type (tons) (Equation U-2 of § 98.213). (4) Annual mass of each output carbonate type (tons) (Equation U-2). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63793, Oct. 24, 2014] § 98.218 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table U-1 to Subpart U of Part 98—CO 2 Mineral name—carbonate CO 2 2 Limestone—CaCO 3 0.43971 Magnesite—MgCO 3 0.52197 Dolomite—CaMg(CO 3 2 0.47732 Siderite—FeCO 3 0.37987 Ankerite—Ca(Fe, Mg, Mn)(CO 3 2 0.47572 Rhodochrosite—MnCO 3 0.38286 Sodium Carbonate/Soda Ash—Na 2 3 0.41492 Subpart V—Nitric Acid Production § 98.220 Definition of source category. This source category includes a nitric acid production facility using one or more trains to produce weak nitric acid (30 to 70 percent in strength). Starting with reporting year 2018, this source category includes all nitric acid production facilities using one or more trains to produce nitric acid (any strength). A nitric acid train produces nitric acid through the catalytic oxidation of ammonia. [81 FR 89259, Dec. 9, 2016] § 98.221 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a nitric acid train and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.222 GHGs to report. (a) You must report N 2 (b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71959, Nov. 29, 2013] § 98.223 Calculating GHG emissions. (a) You must determine annual N 2 (1) Use a site-specific emission factor and production data according to paragraphs (b) through (i) of this section. (2) Request Administrator approval for an alternative method of determining N 2 (i) If you received Administrator approval for an alternative method of determining N 2 (ii) You must notify the EPA of your use of a previously approved alternative method in your annual report. (iii) Otherwise, if you have not received Administrator approval for an alternative method of determining N 2 (iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N 2 (b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (3) of this section. (1) You must conduct the performance test at the absorber tail gas vent, referred to as the test point, for each nitric acid train according to § 98.224(b) through (f). If multiple nitric acid trains exhaust to a common abatement technology and/or emission point, 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 multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains. (2) You must conduct the performance test under normal process operating conditions. (3) You must measure the production rate during the performance test and calculate the production rate for the test period in tons (100 percent acid basis) per hour. (c) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train “t” according to Equation V-1 of this section: where: EF N 2 Ot 2 2 C N2O 2 2 1.14 × 10 −7 2 Q = Volumetric flow rate of effluent gas for each test run during the performance test (dscf/hr). P = Production rate for each test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis). n = Number of test runs. (d) If nitric acid train “t” exhausts to any N 2 2 (1) Use the manufacturer's specified destruction efficiency. (2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency. (3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N 2 (e) If nitric acid train “t” exhausts to any N 2 2 2 where: AF t,N 2 P t P t,N 2 (f) [Reserved] (g) You must calculate N 2 (1) If nitric acid train “t” exhausts to one N 2 where: E N 2 Ot 2 EF N 2 Ot 2 2 P t DF = Destruction efficiency of N 2 2 AF = Abatement utilization factor of N 2 2205 = Conversion factor (lb/metric ton). (2) If multiple N 2 where: E N 2 Ot 2 EF N2O,t 2 2 P t DF 1 2 2 AF 1 2 DF 2 2 2 AF 2 2 DF N 2 2 AF N 2 2205 = Conversion factor (lb/metric ton). N = Number of different N 2 (3) If multiple N 2 where: E N 2 Ot 2 EF N2O,t 2 2 P t DF N 2 2 AF N 2 FC N 2 2205 = Conversion factor (lb/metric ton). N = Number of different N 2 (4) If nitric acid train “t” does not exhaust to any N 2 where: E N 2 Ot 2 EF N 2 Ot 2 2 P t 2205 = Conversion factor (lb/metric ton). (h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility using Equation V-4 of this section: Where: N 2 2 E N 2 Ot 2 m = Number of nitric acid trains. (i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (tons acid produced, 100 percent acid basis), according to § 98.224(f). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66466, Oct. 28, 2010; 78 FR 71959, Nov. 29, 2013; 81 FR 89260, Dec. 9, 2016] § 98.224 Monitoring and QA/QC requirements. (a) You must conduct a new performance test according to a test plan as specified in paragraphs (a)(1) through (3) of this section. (1) Conduct the performance test annually. The test should be conducted at a point during the campaign which is representative of the average emissions rate from the nitric acid campaigns. Facilities must document the methods used to determine the representative point of the campaign when the performance test is conducted. (2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed. (3) If you requested Administrator approval for an alternative method of determining N 2 (b) You must measure the N 2 (1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy. (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference in § 98.7). (3) An equivalent method, with Administrator approval. (c) You must determine the production rate(s) (100 percent acid basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (2) of this section. (1) Direct measurement of production and concentration (such as using flow meters, weigh scales, for production and concentration measurements). (2) Existing plant procedures used for accounting purposes (i.e. dedicated tank-level and acid concentration measurements). (d) You must determine the volumetric flow rate during the performance test in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section. (1) Analysis of samples, determination of emissions, and raw data. (2) All information and data used to derive the emissions factor(s). (3) The production rate during each test and how it was determined. (e) You must determine the total monthly amount of nitric acid produced. You must also determine the monthly amount of nitric acid produced while N 2 (f) You must determine the annual amount of nitric acid produced. You must also determine the annual amount of nitric acid produced while N 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66467, Oct. 28, 2010; 78 FR 71960, Nov. 29, 2013] § 98.225 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of nitric acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records). (b) For missing values related to the performance test, including emission factors, production rate, and N 2 § 98.226 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (q) of this section. (a) Nitric Acid train identification number. (b) Annual process N 2 (c)-(d) [Reserved] (e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis). (f) Number of nitric acid trains. (g) Number of different N 2 (h) Abatement technologies used (if applicable) and date of installation of abatement technology. (i)-(j) [Reserved] (k) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual pressure). (l) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production (months). (m) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (7) of this section. (1) [Reserved] (2) Test method used for performance test. (3)-(6) [Reserved] (7) Number of times in the reporting year that a performance test had to be repeated (number). (n) If you requested Administrator approval for an alternative method of determining N 2 (1) Name of alternative method. (2) Description of alternative method. (3) Request date. (4) Approval date. (o) [Reserved] (p) [Reserved] (q) Annual percent N 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 75 FR 79157, Dec. 17, 2010; 78 FR 71960, Nov. 29, 2013; 79 FR 63793, Oct. 24, 2014; 81 FR 89260, Dec. 9, 2016] § 98.227 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section for each nitric acid production facility: (a) Records of significant changes to process. (b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable). (c) Performance test reports. (d) Number of operating hours in the calendar year for each nitric acid train (hours). (e) Annual nitric acid permitted production capacity (tons). (f) Measurements, records, and calculations used to determine reported parameters. (g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (h) Verification software records. (1) Annual nitric acid produced from each nitric acid train (tons nitric acid produced, 100% acid basis). (2) Indicate which equation was used to calculate emissions for each nitric acid train. (3) N 2 2 (4) Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr) (Equation V-1). (5) Production rate per test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis) (Equation V-1). (6) Annual nitric acid production from each nitric acid train during which each N 2 (7) Destruction efficiency of N 2 2 (8) Destruction efficiency of each N 2 2 (9) Destruction efficiency of each N 2 2 (10) Fraction control factor of each N 2 [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63793, Oct. 24, 2014] § 98.228 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart W—Petroleum and Natural Gas Systems Source: 75 FR 74488, Nov. 30, 2010, unless otherwise noted. § 98.230 Definition of the source category. (a) This source category consists of the following industry segments: (1) Offshore petroleum and natural gas production. (2) Onshore petroleum and natural gas production. (3) Onshore natural gas processing. (4) Onshore natural gas transmission compression. (5) Underground natural gas storage. (6) Liquefied natural gas (LNG) storage. (7) LNG import and export equipment. (8) Natural gas distribution. (9) Onshore petroleum and natural gas gathering and boosting. (10) Onshore natural gas transmission pipeline. (b) [Reserved] [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 79 FR 70385, Nov. 25, 2014; 80 FR 64283, Oct. 22, 2015; 89 FR 42221, May 14, 2024] § 98.231 Reporting threshold. (a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2), except for the industry segments in paragraphs (a)(1) through (4) of this section. (1) Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in § 98.232(c) emit 25,000 metric tons of CO 2 (2) Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in § 98.232(i) emit 25,000 metric tons of CO 2 (3) Facilities must report emissions from the onshore petroleum and natural gas gathering and boosting industry segment only if emission sources specified in § 98.232(j) emit 25,000 metric tons of CO 2 (4) Facilities must report emissions from the onshore natural gas transmission pipeline industry segment only if emission sources specified in § 98.232(m) emit 25,000 metric tons of CO 2 (b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment. [75 FR 74488, Nov. 30, 2010, as amended at 80 FR 64284, Oct. 22, 2015] § 98.232 GHGs to report. (a) You must report CO 2 4 2 4 2 (b) For offshore petroleum and natural gas production, report CO 2 4 2 (1) Equipment leaks ( i.e. (2) Other large release events. (c) For an onshore petroleum and natural gas production facility, report CO 2 4 2 (1) Natural gas pneumatic device venting. (2) Blowdown vent stacks. (3) Natural gas driven pneumatic pump venting. (4) Well venting for liquids unloading. (5) Gas well venting during well completions without hydraulic fracturing. (6) Well venting during well completions with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities). (7) Gas well venting during well workovers without hydraulic fracturing. (8) Well venting during well workovers with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities). (9) Flare stack emissions. (10) Hydrocarbon liquids and produced water storage tank emissions. (11) Reciprocating compressor venting. (12) Well testing venting and flaring. (13) Associated gas venting and flaring from produced hydrocarbons. (14) Dehydrator vents. (15) [Reserved] (16) EOR injection pump blowdown. (17) Acid gas removal unit vents and nitrogen removal unit vents. (18) EOR hydrocarbon liquids dissolved CO 2 (19) Centrifugal compressor venting. (20) [Reserved] (21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this section, as applicable: (i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel). (ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels. (22) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO 2 4 2 (23) Other large release events. (24) Drilling mud degassing. (25) Crankcase vents. (d) For onshore natural gas processing, report CO 2 4 2 (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Dehydrator vents. (5) Acid gas removal unit vents and nitrogen removal unit vents. (6) Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters, and equipment leaks from all other components in gas service (not including thief hatches or other openings on storage vessels) that either are subject to equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (8) Natural gas pneumatic device venting. (9) Other large release events. (10) Hydrocarbon liquids and produced water storage tank emissions. (11) Crankcase vents. (e) For onshore natural gas transmission compression, report CO 2 4 2 (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Condensate storage tanks. (4) Blowdown vent stacks. (5) Natural gas pneumatic device venting. (6) Flare stack emissions. (7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. (8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel. (9) Other large release events. (10) Dehydrator vents. (11) Crankcase vents. (f) For underground natural gas storage, report CO 2 4 2 (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Natural gas pneumatic device venting. (4) Flare stack emissions. (5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters associated with storage stations. (6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). The other components subject to this paragraph (f)(6) do not include thief hatches or other openings on a storage vessel. (7) Equipment leaks from valves, connectors, open-ended lines, and pressure relief valves associated with storage wellheads. (8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (9) Other large release events. (10) Dehydrator vents. (11) Blowdown vent stacks. (12) Condensate storage tanks. (13) Crankcase vents. (g) For LNG storage, report CO 2 4 2 (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Flare stack emissions. (4) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service. (5) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (g)(6) of this section. (6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (8) Other large release events. (9) Blowdown vent stacks. (10) Acid gas removal unit vents and nitrogen removal unit vents. (11) Crankcase vents. (h) LNG import and export equipment, report CO 2 4 2 (1) Reciprocating compressor venting. (2) Centrifugal compressor venting. (3) Blowdown vent stacks. (4) Flare stack emissions. (5) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service. (6) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (h)(7) of this section. (7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and either are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or § 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or that you elect to survey using a leak detection method described in § 98.234(a). (9) Acid gas removal unit vents and nitrogen removal unit vents. (10) Other large release events. (11) Crankcase vents. (i) For natural gas distribution, report CO 2 4 2 (1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations. (2) Equipment leaks at below grade transmission-distribution transfer stations. (3) Equipment leaks at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations. (4) Equipment leaks at below grade metering-regulating stations. (5) Distribution main equipment leaks. (6) Distribution services equipment leaks. (7) Report under subpart W of this part the emissions of CO 2 4 2 (8) Other large release events. (9) Blowdown vent stacks. (10) Natural gas pneumatic device venting. (11) Crankcase vents. (j) For an onshore petroleum and natural gas gathering and boosting facility, report CO 2 4 2 (1) Natural gas pneumatic device venting. (2) Natural gas driven pneumatic pump venting. (3) Acid gas removal unit vents and nitrogen removal unit vents. (4) Dehydrator vents. (5) Blowdown vent stacks. (6) Hydrocarbon liquids and produced water storage tank emissions. (7) Flare stack emissions. (8) Centrifugal compressor venting. (9) Reciprocating compressor venting. (10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this section, as applicable: (i) Equipment leaks from components including valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel). (ii) Equipment leaks from major equipment including wellheads, separators, meters/piping, compressors, dehydrators, heaters, and storage vessels. (11) Gathering pipeline equipment leaks. (12) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO 2 4 2 (13) Other large release events. (14) Crankcase vents. (k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 (l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO 2 (m) For onshore natural gas transmission pipeline, report CO 2 4 2 (1) Blowdown vent stacks. (2) Other large release events. (3) Equipment leaks listed in paragraph (m)(3)(i) or (ii) of this section, as applicable: (i) Equipment leaks at transmission company interconnect metering-regulating stations. (ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at transmission company interconnect metering-regulating stations. (4) Equipment leaks listed in paragraph (m)(4)(i) or (ii) of this section, as applicable: (i) Equipment leaks at farm tap and/or direct sale metering-regulating stations. (ii) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters at farm tap and/or direct sale metering-regulating stations. (5) Transmission pipeline equipment leaks. [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80574, Dec. 23, 2011; 79 FR 70385, Nov. 25, 2014; 80 FR 64284, Oct. 22, 2015; 81 FR 86511, Nov. 30, 2016; 89 FR 42221, May 14, 2024] § 98.233 Calculating GHG emissions. You must calculate and report the annual GHG emissions as prescribed in this section. For calculations that specify measurements in actual conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section. (a) Natural gas pneumatic device venting. 4 2 4 2 4 2 (1) Calculation Method 1. 4 2 (i) For volumetric flow monitors: (A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are routed to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual volumetric flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year the devices were in service ( i.e., i.e., (B) Convert the natural gas volumetric flow from paragraph (a)(1)(i)(A) of this section to CH 4 2 (C) Convert the CH 4 2 4 2 (ii) For mass flow monitors: (A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If all natural gas pneumatic devices supplied by the measured natural gas supply line are vented directly to the atmosphere for only a portion of the year and are routed to a flare, combustion, or vapor recovery system for the remaining portion of the year, determine the cumulative annual mass flow considering only those times when one or more of the natural gas pneumatic devices were vented directly to the atmosphere. If the flow meter was installed during the year, calculate the total mass flow for the year based on the measured mass flow times the total hours in the calendar year the devices were in service ( i.e., i.e., (B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A) of this section to CH 4 2 4 2 4 2 4 2 (iii) If the flow meter on the natural gas supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate the total measured amount of natural gas to pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data. (iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b). (2) Calculation Method 2. (i) For facilities in the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, you may elect to measure your pneumatic devices according to this Calculation Method 2 for some well-pad sites or gathering and boosting sites and use other methods for other sites. When you elect to measure the emissions from natural gas pneumatic devices according to this Calculation Method 2 at a well-pad site or gathering and boosting site, you must measure all natural gas pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year and you must measure and calculate emissions according to the provisions in paragraphs (a)(2)(iii) through (viii) of this section. (ii) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments electing to use this Calculation Method 2, you must measure all natural gas pneumatic devices vented directly to the atmosphere at your facility each year or, if your facility has 26 or more pneumatic devices, over multiple years, not to exceed the number of years as specified in paragraphs (a)(2)(ii)(A) through (D) of this section. If you elect to measure your pneumatic devices over multiple years, you must measure approximately the same number of devices each year. You must measure and calculate emissions for natural gas pneumatic devices at your facility according to the provisions in paragraphs (a)(2)(iii) through (ix), as applicable. (A) If your facility has at least 26 but not more than 50 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 2 years. (B) If your facility has at least 51 but not more than 75 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 3 years. (C) If your facility has at least 76 but not more than 100 natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 4 years. (D) If your facility has 101 or more natural gas pneumatic devices vented directly to the atmosphere, the maximum number of years to measure all devices at your facility is 5 years. (iii) For all industry segments, determine the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (a)(2)(iii)(A) through (E) of this section. You must measure the emissions under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device. (A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each device for a minimum of 15 minutes while the device is in service (i.e., supplied with natural gas), except for natural gas pneumatic isolation valve actuators. For natural gas pneumatic isolation valve actuators, you must measure the emissions from each device for a minimum of 5 minutes while the device is in service ( i.e., (B) If you use calibrated bagging, follow the methods set forth in § 98.234(c) except you need only fill one bag to have a valid measurement. You must collect sample for a minimum of 5 minutes for natural gas pneumatic isolation valve actuators or 15 minutes for other natural gas pneumatic devices. If no gas is collected in the calibrated bag during the minimum sampling period, you can discontinue monitoring and follow the applicable methods in paragraph (a)(2)(v) of this section. If gas is collected in the bag during the minimum sampling period, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (a)(2)(iii)(A) of this section. (C) You do not need to use the same measurement method for each natural gas pneumatic device vent. (D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section. (E) If there is measurable flow from the device vent, calculate the volumetric flow rate of each natural gas pneumatic device vent (in standard cubic feet per hour) by dividing the cumulative volume of natural gas measured during the measurement period (in standard cubic feet) by the duration of the measurement (in hours). (iv) For all industry segments, if there is measurable flow from the device vent, calculate the volume of natural gas emitted from each natural gas pneumatic device vent as the product of the natural gas flow rate measured in paragraph (a)(2)(iii) of this section and the number of hours the pneumatic device was in service ( i.e., (v) For all industry segments, if there is no measurable flow from the device vent, estimate the emissions from the device according to the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as applicable. (A) For continuous high bleed pneumatic devices: ( 1 ( 2 ( 3 1 2 (B) For continuous low bleed pneumatic devices: ( 1 ( 2 4 ( 3 2 i.e. ( 4 (C) For intermittent bleed pneumatic devices: ( 1 2 5 ( 2 ( 3 2 ( 4 ( 5 4 (vi) For each pneumatic device, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (a)(2)(iv) or (v) of this section, as applicable, to CO 2 4 (vii) For each pneumatic device, convert the GHG volumetric emissions at standard conditions determined in paragraph (a)(2)(vi) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section. (viii) Sum the CO 2 4 (ix) For facilities in the onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, or natural gas distribution industry segments, if you chose to conduct natural gas pneumatic device measurements over multiple years, “n,” according to paragraph (a)(2)(ii) of this section, then you must calculate the emissions from all pneumatic devices at your facility as specified in paragraph (a)(2)(ix)(A) through (E) of this section. (A) Use the emissions calculated in (a)(2)(viii) of this section for the devices measured during the reporting year. (B) Calculate the whole gas emission factor for each type of pneumatic device at the facility using equation W-1A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic device vent measurements were made according to Calculation Method 2 in paragraph (a)(2) of this section ( e.g., Where: EF t MT s,t,y 2 6 Count t,y n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic device vents at the facility. (C) Calculate CH 4 2 Where: E s,i i Count t EF t GHG i i 4 2 T t i.e., (D) Convert the volumetric emissions calculated using equation W-1B to this section to CH 4 2 (E) Sum the CH 4 2 4 2 (3) Calculation Method 3. 4 2 (i) For continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere, you must calculate CH 4 2 (A) Measure all continuous high bleed and continuous low bleed pneumatic devices at your well-pad site or gathering and boosting site, as applicable, according to the provisions in paragraphs (a)(2) of this section. (B) Use equation W-1B to this section, except use the appropriate default whole gas population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type “t” (continuous high bleed and continuous low bleed) as listed in table W-1 to this subpart. (ii) For intermittent bleed pneumatic devices, you must monitor each intermittent bleed pneumatic device at your well-pad site or gathering and boosting site as specified in paragraphs (a)(3)(ii)(A) through (C) of this section, as applicable. (A) You must use one of the monitoring methods specified in § 98.234(a)(1) through (3) except that the monitoring dwell time for each device vent must be at least 2 minutes or until a malfunction is identified, whichever is shorter. A device is considered malfunctioning if any leak is observed when the device is not actuating or if a leak is observed for more than 5 seconds, or the extended duration as specified in paragraph (a)(3)(ii)(C) of this section if applicable, during a device actuation. If you cannot tell when a device is actuating, any observed leak from the device indicates a malfunctioning device. (B) If you elect to monitor emissions from natural gas pneumatic devices at a well-pad site or gathering and boosting site according to this Calculation Method 3, you must monitor all natural gas intermittent bleed pneumatic devices that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year. You must monitor the natural gas intermittent bleed pneumatic devices under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the device or manually actuating the device. (C) For certain throttling pneumatic devices or isolation valve actuators on pipes greater than 5 inches in diameter, that may actuate for more than 5 seconds under normal conditions, you may elect to identify individual devices for which longer bleed periods may be allowed as specified in paragraphs (a)(3)(ii)(C)( 1 2 ( 1 ( 2 (iii) For intermittent bleed pneumatic devices that are monitored according to paragraph (a)(3)(ii) of this section during the reporting year, you must calculate CH 4 2 Where: E i GHG i 4 2 x = Total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the year. A component found as malfunctioning in two or more surveys during the year is counted as one malfunctioning component. K 1 T mal,z i.e., T t,z i.e., K 2 Count = Total number of intermittent bleed natural gas pneumatic devices that were never observed to be malfunctioning during any monitoring survey during the year. T avg i.e., (A) You must conduct at least one complete pneumatic device monitoring survey in a calendar year. If you conduct multiple complete pneumatic device monitoring surveys in a calendar year, you must use the results from each complete pneumatic device monitoring survey when calculating emissions using equation W-1C to this section. (B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a complete monitoring survey is a survey of all intermittent bleed natural gas pneumatic devices vented directly to the atmosphere at a well-pad site for onshore petroleum and natural gas production facilities (except those measured according to paragraph (a)(1) of this section) or all intermittent bleed pneumatic devices vented directly to the atmosphere at a gathering and boosting site for onshore petroleum and natural gas gathering and boosting facilities (except those measured according to paragraph (a)(1) of this section). (iv) You must convert the CH 4 2 2 4 (4) Calculation Method 4. 4 2 (i) You must calculate CH 4 2 (ii) You must convert the CH 4 2 2 4 (5) Counts of natural gas pneumatic devices. (6) Counts of onshore petroleum and natural gas production industry segment or the onshore petroleum and natural gas gathering and boosting natural gas pneumatic devices. (7) Type of natural gas pneumatic devices. (8) Routing to flares, combustion, or vapor recovery systems. (i) If any natural gas pneumatic devices were routed to a flare, you must calculate CH 4 2 2 (ii) If emissions from any natural gas pneumatic devices were routed to combustion units, you must calculate and report emissions as specified in subpart C of this part or calculate emissions as specified in paragraph (z) of this section and report emissions from the combustion equipment as specified in § 98.236(z), as applicable. (b) [Reserved] (c) Natural gas driven pneumatic pump venting. 4 2 4 2 4 2 (1) Calculation method 1. 4 2 (i) For volumetric flow monitors: (A) Determine the cumulative annual volumetric flow, in standard cubic feet, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total volumetric flow for the year based on the measured volumetric flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the volumetric flow was being measured. (B) Convert the natural gas volumetric flow from paragraph (c)(1)(i)(A) of this section to CH 4 2 (C) Convert the CH 4 2 4 2 (ii) For mass flow monitors: (A) Determine the cumulative annual mass flow, in metric tons, as measured by the flow monitor in the reporting year. If the flow meter was installed during the year, calculate the total mass flow of vented natural gas emissions for the year based on the measured mass flow times the total hours in the calendar year in which at least one of the pumps connected to the supply line was pumping liquid divided by the number of hours in the year when at least one of pumps connected to the supply line was pumping liquid and the mass flow was being measured. (B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A) of this section to CH 4 2 4 2 4 2 4 2 (iii) If the supply line serves both natural gas pneumatic devices and natural gas driven pneumatic pumps, disaggregate the total measured amount of natural gas to natural gas pneumatic devices and natural gas driven pneumatic pumps based on engineering calculations and best available data. (iv) The flow meter must be operated and calibrated according to the methods set forth in § 98.234(b). (2) Calculation Method 2. (i) Measure all natural gas driven pneumatic pumps at your facility at least once every 5 years. If you elect to measure your pneumatic pumps over multiple years, you must measure approximately the same number of pumps each year. When you measure the emissions from natural gas driven pneumatic pumps at a well-pad site or gathering and boosting site, you must measure all pneumatic pumps that are vented directly to the atmosphere at the well-pad site or gathering and boosting site during the same calendar year. (ii) Determine the volumetric flow rate of each natural gas driven pneumatic pump (in standard cubic feet per hour) using one of the methods specified in § 98.234(b) through (d), as appropriate, according to the requirements specified in paragraphs (c)(2)(ii)(A) through (D) of this section. You must measure the emissions under conditions representative of normal operations, which excludes periods immediately after conducting maintenance on the pump. (A) If you use a temporary meter, such as a vane anemometer, according to the methods set forth in § 98.234(b) or a high volume sampler according to methods set forth in § 98.234(d), you must measure the emissions from each pump for a minimum of 5 minutes, during a period when the pump is continuously pumping liquid. (B) If you use calibrated bagging, follow the methods set forth in § 98.234(c), except under § 98.234(c)(2), only one bag must be filled to have a valid measurement. You must collect sample for a minimum of 5 minutes, or until the bag is full, whichever is shorter, during a period when the pump is continuously pumping liquid. If the bag is not full after 5 minutes, you must either continue sampling until you fill the calibrated bag or you may elect to remeasure the vent according to paragraph (c)(2)(ii)(A) of this section. (C) You do not need to use the same measurement method for each natural gas driven pneumatic pump vent. (D) If the measurement method selected measures the volumetric flow rate in actual cubic feet, convert the measured flow to standard cubic feet following the methods specified in paragraph (t)(1) of this section. Convert the measured flow during the test period to standard cubic feet per hour, as appropriate. (iii) Calculate the volume of natural gas emitted from each natural gas driven pneumatic pump vent as the product of the natural gas emissions flow rate measured in paragraph (c)(2)(ii) of this section and the number of hours that liquid was pumped by the pneumatic pump in the calendar year. (iv) For each pneumatic pump, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (c)(2)(iii) of this section to CO 2 4 (v) For each pneumatic pump, convert the GHG volumetric emissions at standard conditions determined in paragraph (c)(2)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section. (vi) Sum the CO 2 4 (vii) If you chose to conduct natural gas pneumatic pump measurements over multiple years, “n,” according to paragraph (c)(2)(i) of this section, then you must calculate the emissions from all pneumatic pumps at your facility as specified in paragraph (c)(2)(vii)(A) through (D) of this section. (A) Use the emissions calculated in paragraph (c)(2)(vi) of this section for the pumps measured during the reporting year. (B) Calculate the whole gas emission factor for pneumatic pumps at the facility using equation W-2A to this section and all available data from the current year and the previous years in your monitoring cycle (n-1 years) for which natural gas pneumatic pump vent measurements were made according to Calculation Method 2 in paragraph (c)(2) of this section ( e.g. Where: EF s MT s,y Count y n = Number of years of data to include in the emission factor calculation according to the number of years used to monitor all natural gas pneumatic pump vents at the facility. (C) Calculate CH 4 2 Where: E s,i i Count = Total number of natural gas driven pneumatic pumps that vented directly to the atmosphere and that were not directly measured according to the requirements in paragraphs (c)(1) or (c)(2)(ii) of this section. EF s GHG i i 4 2 T = Average estimated number of hours in the operating year the pumps that vented directly to the atmosphere were pumping liquid using engineering estimates based on best available data. Default is 8,760 hours for pumps that only vented directly to the atmosphere. (D) Calculate both CH 4 2 (E) Sum the CH 4 2 4 2 (3) Calculation Method 3 4 2 (i) Calculate CH 4 2 (ii) Convert the CH 4 2 2 4 (4) Routing to flares, combustion, or vapor recovery systems (i) If any natural gas driven pneumatic pumps were routed to a flare, you must calculate CH 4 2 2 (ii) If emissions from any natural gas driven pneumatic pumps were routed to combustion, you must calculate emissions for the combustion equipment as specified in paragraph (z) of this section and report emissions from the combustion equipment as specified in § 98.236(z). (d) Acid gas removal unit (AGR) vents and Nitrogen removal unit (NRU) vents. 4 2 4 4 2 2 e.g., i.e., 4 2 2 (1) Calculation Method 1 2 2 2 2 (2) Calculation Method 2 2 2 4 2 4 Where: E a,i 2 4 V a Vol i 2 4 (3) Calculation Method 3 2 4 2 4 2 4 2 4 2 Where: E a,i i 4 2 V in V out Vol I,i i 4 2 Vol O,i i 4 2 Vol EM,i i 4 2 (4) Calculation Method 4 2 4 2 4 2 i.e. 2 4 2 (i) Natural gas feed temperature, pressure, and flow rate (must be measured). (ii) Acid gas content of feed natural gas (must be measured). (iii) Acid gas content of outlet natural gas. (iv) CH 4 (v) CH 4 (vi) For NRU, nitrogen content of feed natural gas (must be measured). (vii) For NRU, nitrogen content of outlet natural gas. (viii) Unit operating hours, excluding downtime for maintenance or standby. (ix) Exit temperature of natural gas. (x) For AGR, solvent type, pressure, temperature, circulation rate, and composition. (5) Flow rate of inlet or outlet (6) Composition of vent gas i EM,i (7) Composition of inlet gas stream (8) Composition of outlet gas stream 4 2 (i) If a continuous gas analyzer is installed on the outlet natural gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet natural gas stream for each quarter that the AGR or NRU is operating to determine Vol O,i (iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipeline quality specification for CO 2 4 (9) Comparison of annual volume of vent gas. If a vent meter is installed but you wish to use Calculation Method 4 rather than Calculation Method 2 for an AGR, use equation W-4D to this section to determine the difference between the annual volume of vent gas measured by the vent meter and the simulated annual volume of vent gas. Where: PD = Percent difference between vent gas volumes, %. V a,meter V a,sim (10) Volumetric emissions 4 2 (11) Emissions vented directly to atmosphere from AGRs or NRUs routed to vapor recovery systems or flares (i) Calculate vented emissions as specified in paragraph (d)(1), (2), (3), or (4) of this section, which represents the emissions from the AGR vent or NRU vent prior to the vapor recovery system or flare. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the AGR or NRU was in operation. (ii) To calculate vented emissions during periods when the AGR vent or NRU vent was not routing emissions to a vapor recovery system or a flare, multiply the average hourly vented emissions rate determined in paragraph (d)(11)(i) of this section by the number of hours that the AGR or NRU vented directly to the atmosphere. Determine the number of hours that the AGR or NRU vented directly to atmosphere by subtracting the hours that the AGR or NRU was connected to a vapor recovery system or flare (based on engineering estimate and best available data) from the total operating hours for the AGR or NRU in the calendar year. You must take into account periods with reduced capture efficiency of the vapor recovery system or flare. (12) Mass emissions 4 2 (e) Dehydrator vents. 4 2 4 2 4 2 2 4 2 2 (1) Calculation Method 1 4 2 (i) Feed natural gas flow rate (based on measured data). (ii) Feed natural gas water content (must be measured). (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric). (v) Absorbent circulation rate. (vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)). (vii) Use of stripping gas. (viii) Use of flash tank separator (and disposition of recovered gas). (ix) Hours operated. (x) Wet natural gas temperature and pressure at the absorber inlet (must be measured). (xi) Wet natural gas composition. Measure this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) and (B) of this section. (A) Use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition. (B) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Method 2. 4 2 Where: E s,i 2 4 EF i 4 2 Count = Total number of glycol dehydrators that have an annual average daily natural gas throughput that is greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day for which you elect to use this Calculation Method 2. 1000 = Conversion of EF i (3) Calculation Method 3 4 2 Where: E s,n H = Height of the dehydrator vessel (ft). D = Inside diameter of the vessel (ft). P 1 P 2 π = pi (3.14). %G = Percent of packed vessel volume that is gas. N = Number of dehydrator openings in the calendar year. 100 = Conversion of %G to fraction. (4) Emissions vented directly to atmosphere from dehydrators routed to a vapor recovery system, flare, or regenerator firebox/fire tubes. (i) When emissions from dehydrator(s) are calculated using Calculation Method 1 or 2, calculate vented emissions as specified in paragraph (e)(1) or (2) of this section, which represents the emissions from the dehydrator prior to the vapor recovery system, flare, or regenerator firebox/fire tubes. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the dehydrator was in operation. (ii) To calculate total emissions vented directly to atmosphere during periods when the dehydrator was not routing emissions to a vapor recovery system, flare, or regenerator firebox/fire tubes for dehydrator(s) with emissions calculated using Calculation Method 1 or 2, multiply the average hourly vented emissions rate determined in paragraph (e)(4)(i) of this section by the number of hours that the dehydrator vented directly to the atmosphere. Determine the number of hours that the dehydrator vented directly to atmosphere by subtracting the hours that the dehydrator was connected to a vapor recovery system, flare, or regenerator firebox/fire tubes (based on engineering estimate and best available data) from the total operating hours for the dehydrator in the calendar year. You must take into account periods with reduced capture efficiency of the vapor recovery system, flare, or regenerator firebox/fire tubes. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). (iii) When emissions from dehydrator(s) are calculated using Calculation Method 3, calculate total annual emissions vented directly to atmosphere from the dehydrator(s) during periods of time when emissions were not routed to the vapor recovery system, flare, or other non-flare combustion unit by determining of the number of depressurization events (including portions of an event) that vented to atmosphere based on engineering estimate and best available data. You must take into account periods with reduced capture efficiency of the vapor recovery system, flare, or other non-flare combustion unit. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). (5) Combustion emissions from routing to regenerator firebox/fire tubes or other non-flare combustion unit. (i) Determine the volume of the total emissions that is routed to a regenerator firebox/fire tubes or other non-flare combustion unit as specified in paragraph (e)(5)(i)(A) or (B) of this section. (A) Measure the flow from the dehydrator(s) to the regenerator firebox/fire tubes or other non-flare combustion unit using a continuous flow measurement device. If you continuously measure flow to the regenerator firebox/fire tubes or other non-flare combustion unit, you must use the measured volumes to calculate emissions from the regenerator firebox/fire tubes or other non-flare combustion unit. (B) Using engineering estimates based on best available data, determine the volume of the total emissions estimated in paragraph (e)(1), (2), or (3) of this section, as applicable, that is routed to the regenerator firebox/fire tubes or other non-flare combustion unit. (ii) Determine composition of the gas routed to a regenerator firebox/fire tubes or other non-flare combustion unit as specified in paragraph (e)(5)(ii)(A) or (B) of this section. (A) Use the appropriate vent emissions as determined in paragraph (e)(1) or (2) of this section. (B) Measure the composition of the gas from the dehydrator(s) to the regenerator firebox/fire tubes or other non-flare combustion unit using a continuous composition analyzer. If you continuously measure gas composition, then those measured data must be used to calculate dehydrator emissions from the regenerator firebox/fire tubes or other non-flare combustion unit. (iii) Determine GHG volumetric emissions at actual conditions from the regenerator firebox/fire tubes or other non-flare combustion unit using equations W-39A, W-39B, and W-40 to this section. Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. Calculate both GHG mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (iv) If you operate and maintain a CEMS that has both a CO 2 2 (f) Well venting for liquids unloadings. 4 2 4 2 2 (1) Calculation Method 1. Where: E a FR = Average flow rate in cubic feet per hour for all measured wells of the same tubing diameter group and pressure group combination in a sub-basin, over the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section. T p Where: HR p MP p D p (i) Determine the well vent average flow rate (“FR” in equation W-7A to this section) as specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with automated plunger lift unloadings, wells with manual plunger lift unloadings, wells with automated unloadings without plunger lifts and wells with manual unloadings without plunger lifts separately. (A) Calculate the average flow rate per hour of venting for each unique tubing diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere. (B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to each well in the same pressure group that have the same tubing diameter group, for the number of hours that each well is vented to the atmosphere. (C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (2) Calculation Method 2 Where: E s N p 0.37×10 −3 CD p WD p SP p SFR p HR p,q 1.0 = Hours for average well to blowdown casing volume at shut-in pressure. q = Unloading event. Z p,q (3) Calculation Method 3. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading with plunger lift assist using equation W-9 to this section. Where: E s N p 0.37×10 −3 TD p WD p SP p SFR p HR p,q 0.5 = Hours for average well to blowdown tubing volume at flow-line pressure. q = Unloading event. Z p,q p,q p,q p,q p,q (4) Volumetric and mass emissions 4 2 (g) Well venting during completions and workovers with hydraulic fracturing 4 2 4 2 2 Where: E s,n CW = Total number of completions or workovers using hydraulic fracturing. T p,s T p,i FRM s FRM i PR s,p EnF s,p 2 FV s,p FR p,i Z p,i p,i p,i (1) If you elect to use equation W-10A to this section on gas wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section. If you are unable to measure the gas flowback rates using a recording flow meter for gas well completions or workovers as described in Calculation Method 1, for example due to field conditions, operating conditions, or health and safety considerations, you may use Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section to determine the value of FRM s i s i (i) Calculation Method 1 s i (ii) Calculation Method 2 (for gas wells) s i a s,p i,p Where: FR a A = Cross sectional open area of the restriction orifice (m 2 P 1 T u P 2 3430 = Constant with units of m 2 2 1.27*10 5 3 3 Where: FR a A = Cross sectional open area of the restriction orifice (m 2 T u 187.08 = Constant with units of m 2 2 1.27*10 5 3 3 Where: R = Pressure ratio. P 1 P 2 (iii) For equation W-10A to this section, calculate FRMs using equation W-12A to this section. Where: FRM s FR s,p a a s,p PR s,p s,p N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination. (iv) For equation W-10A to this section, calculate FRMi using equation W-12B to this section. Where: FRM i FR i,p i,p PR s,p s,p N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination. (v) For equation W-10A to this section, the ratio of gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate are applied to all well completions and well workovers, respectively, in the sub-basin and well type combination for the total number of hours of flowback and for the first 30 day average gas production rate for each of these wells. (vi) For equations W-12A and W-12B to this section, calculate new flowback rates for well completions and well workovers in each sub-basin and well type combination once every two years starting in the first calendar year of data collection. (vii) For oil wells where the gas production rate is not metered and you elect to use equation W-10A to this section, calculate the average gas production rate (PR s,p Where: PR s,p GOR p V p 720 = Conversion from 30 days of production to hourly production rate. (A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (B) You may use an industry standard practice as described in § 98.234(b). (2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (iv) of this section. (i) Vertical or horizontal (directional drilling). (ii) With flaring or without flaring. (iii) Reduced emission completion/workover or not reduced emission completion/workover. (iv) Oil well or gas well. (3) Calculate both CH 4 2 (h) Gas well venting during completions and workovers without hydraulic fracturing 4 2 4 2 2 Where: E s,wo N wo EF wo E s,p V p T p (1) Calculate both CH 4 2 4 2 (2) [Reserved] (i) Blowdown vent stacks 2 4 4 2 2 (1) Method for calculating unique physical volumes or distribution pipeline physical volumes. (2) Method for determining emissions from blowdown vent stacks according to equipment or event type (i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down using either equation W-14A or W-14B to this section. Where: E s,n N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. V = Unique physical volume, in cubic feet, as calculated in paragraph (i)(1) of this section. C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the unique physical volume is purged using non-GHG gases. T s T a P s a Z a Where: E s,n p = Individual occurrence of blowdown for the same unique physical volume. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. V p T s a,p P s P a,b,p P a,e,p Z a (ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH 4 2 4 2 4 2 (iii) For onshore natural gas transmission compression facilities and LNG import and export equipment, as an alternative to using the procedures in paragraph (i)(2)(ii) of this section, you may elect to sum the annual natural gas emissions as calculated using either equation W-14A or equation W-14B to this section for all unique physical volumes associated with the equipment type or event type. Calculate the total annual CH 4 2 (iv) Categorize blowdown vent stack emission events as specified in paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable. (A) For the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, and onshore petroleum and natural gas gathering and boosting industry segments, equipment or event types must be grouped into the following seven categories: Facility piping ( i.e., i.e., (B) For the onshore natural gas transmission pipeline and natural gas distribution industry segments, pipeline segments or event types must be grouped into the following eight categories: Pipeline integrity work ( e.g., e.g., e.g. (3) Method for determining emissions from blowdown vent stacks using a flow meter. 4 2 (4) Method for converting from natural gas emissions to GHG volumetric and mass emissions. 4 2 (j) Hydrocarbon liquids and produced water storage tanks. 4 2 4 e.g., 4 2 4 2 4 4 2 4 2 2 (1) Calculation Method 1. 4 2 4 4 2 i.e., (i) Well, separator, or non-separator equipment temperature (must be measured at least annually if required as an input for the model). (ii) Well, separator, or non-separator equipment pressure (must be measured at least annually if required as an input for the model). (iii) [Reserved] (iv) Sales or stabilized hydrocarbon liquids or produced water production rate (must be measured at least annually if required as an input for the model). (v) Ambient air temperature. (vi) Ambient air pressure. (vii) Sales or stabilized hydrocarbon liquids API gravity, and well, separator, or non-separator equipment hydrocarbon liquids or produced water composition and Reid vapor pressure (must be measured if required as an input for the model). Use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze sales or stabilized hydrocarbon liquids for API gravity, and hydrocarbon liquids or produced water composition and Reid vapor pressure. You must sample and analyze sales or stabilized oil for API gravity, and hydrocarbon liquids or produced water for composition and Reid vapor pressure within six months of equipment start-up or by January 1, 2030, whichever is later, and at least once every five years thereafter. Until such time that a sample is collected, determine API gravity by engineering estimate and process knowledge based on best available data, and determine composition and Reid vapor pressure by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section. For produced water, you may instead elect to use a representative sales oil or stabilized hydrocarbon liquid API gravity and a hydrocarbon liquid composition and Reid vapor pressure, and assume oil entrainment of 1 percent or greater. (A) If separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator or non-separator equipment pressure first, and API gravity secondarily. (B) If separator or non-separator equipment hydrocarbon liquids composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of hydrocarbon liquids from the sub-basin category for onshore petroleum and natural gas production or from the county for onshore petroleum and natural gas gathering and boosting. (C) Analyze a representative sample of separator or non-separator equipment hydrocarbon liquids in each sub-basin category for onshore petroleum and natural gas production or each county for onshore petroleum and natural gas gathering and boosting for hydrocarbon liquids composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization. (2) Calculation Method 2. 4 2 4 (i) Assume that all of the CH 4 2 (ii) [Reserved] (3) Calculation Method 3. 4 2 4 (i) Calculate CH 4 2 Where: E s,i 2 4 EF i 4 2 4 2 Count = Total number of separators, wells, or non-separator equipment with annual average daily throughput greater than 0 barrels per day and less than 10 barrels per day. Count only separators, wells, or non-separator equipment that feed hydrocarbon liquids directly to the atmospheric pressure storage tank for which you elect to use this Calculation Method 3. 1,000 = Conversion from thousand standard cubic feet to standard cubic feet. (ii) Calculate CH 4 Where: Mass CH 4 4 EF CH 4 4 FR = Annual flow rate of produced water to atmospheric pressure storage tanks, in barrels. 0.001 = Conversion from barrels to thousand barrels. (4) Emissions vented directly to atmosphere from atmospheric pressure storage tanks routed to vapor recovery systems or flares. (i) For an atmospheric pressure storage tank that routes any emissions to a vapor recovery system or a flare, calculate vented emissions as specified in paragraphs (j)(4)(i)(A) through (E) of this section. (A) Calculate vented emissions as specified in paragraph (j)(1), (2), or (3) of this section, which represents the emissions from the atmospheric storage tank prior to the vapor recovery system or flare. Calculate an average hourly vented emissions rate by dividing the vented emissions by the number of hours that the tank was in operation. (B) To calculate vented emissions during periods when the tank was not routing emissions to a vapor recovery system or a flare, multiply the average hourly vented emissions rate determined in paragraph (j)(4)(i)(A) of this section by the number of hours that the tank vented directly to the atmosphere. Determine the number of hours that the tank vented directly to atmosphere by subtracting the hours that the tank was connected to a vapor recovery system or flare (based on engineering estimate and best available data) from the total operating hours for the tank in the calendar year. If emissions are routed to a flare but the flare is unlit, calculate emissions in accordance with the methodology specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n). (C) During periods when a thief hatch is open and emissions from the tank are routed to a vapor recovery system or a flare, assume the capture efficiency of the vapor recovery system or a flare is 0 percent. A thief hatch is open if it is fully or partially open such there is a visible gap between the hatch cover and the hatch portal. To calculate vented emissions during such periods, multiply the average hourly vented emissions rate determined in paragraph (j)(4)(i)(A) of this section by the number of hours that the thief hatch is open. Determine the number of hours that the thief hatch is open as specified in paragraph (j)(7) of this section. (D) Calculate vented emissions not captured by the vapor recovery system or a flare due to causes other than open thief hatches based on best available data, including any data from operating pressure sensors on atmospheric pressure storage tanks. (E) Calculate total emissions vented directly to atmosphere as the sum of the emissions calculated as specified in paragraphs (j)(4)(i)(B) through (D) of this section. (ii) Using engineering estimates based on best available data, determine the portion of the total emissions estimated in paragraphs (j)(1) through (3) of this section that is recovered using a vapor recovery system. You must take into account periods with reduced capture efficiency of the vapor recovery system ( e.g., (5) Gas-liquid separator dump valves Where: E s,i,dv 2 4 CF dv dv dv E s,i 2 4 8,760 = Conversion to hourly emissions. T dv (i) If a parametric monitor is operating on a controlled atmospheric pressure storage tank or gas-liquid separator, you must use data obtained from the parametric monitor to determine periods when the gas-liquid separator liquid dump valve is stuck in an open or partially open position. An applicable operating parametric monitor must be capable of logging data whenever a gas-liquid separator liquid dump valve is stuck in an open or partially open position, as well as when the gas-liquid separator liquid dump valve is subsequently closed. If an applicable parametric monitor is not operating, including during periods of time when the parametric monitor is malfunctioning, you must perform an audio, visual, and olfactory inspection of each gas-liquid separator liquid dump valve to determine if the valve is stuck in an open or partially open position, in accordance with paragraphs (j)(5)(i)(A) and (B) of this section. (A) Audio, visual and olfactory inspections must be conducted at least once in a calendar year. (B) If stuck gas-liquid separator liquid dump valve is identified, the dump valve must be counted as being open since the beginning of the calendar year, or from the previous audio, visual, and olfactory inspection that did not identify the dump valve as being stuck in the open position in the same calendar year. If the dump valve is fixed following audio, visual, and olfactory inspection, the time period for which the dump valve was stuck open will end upon being repaired. If a stuck dump valve is identified and not repaired, the time period for which the dump valve was stuck open must be counted as having occurred through the rest of the calendar year. (ii) [Reserved] (6) Mass emissions. 4 2 (7) Thief hatches (i) For thief hatches on controlled atmospheric pressure storage tanks subject to the standards in § 60.5395b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, visual inspections must be conducted at least as frequent as the required audio, visual, and olfactory inspections described in § 60.5416b or the applicable approved state plan or applicable Federal plan in part 62. If the time between required audio, visual, and olfactory inspections described in § 60.5416b or the applicable approved state plan or applicable Federal plan in part 62 is greater than one year, visual inspections must be conducted at least annually. (ii) For thief hatches on controlled atmospheric pressure storage tanks not subject to the standards in § 60.5395b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, visual inspections must be conducted at least once in a calendar year. (iii) If one visual inspection is conducted in the calendar year and an open thief hatch is found, assume the thief hatch was open for the entire calendar year or the entire period that the sensor(s) was not operating or malfunctioning. If multiple visual inspections are conducted in the calendar year, assume a thief hatch found open in the first visual inspection was open since the beginning of the year until the date of the visual inspection; assume a thief hatch found open in the last visual inspection of the year was open from the preceding visual inspection through the end of the year; assume a thief hatch found open in a visual inspection between the first and last visual inspections of the year was open since the preceding visual inspection until the date of the visual inspection. (k) Condensate storage tanks. 4 2 4 2 2 (1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (iii) of this section. (i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1). (ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes. (iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, whichever is shorter. (iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection device detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (ii) of this section. (i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the measurement. (ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5). (3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leaking dump valve is fixed following leak detection, the leak duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having occurred through the rest of the calendar year. (4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to quantify annual emissions. (i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. (ii) Calculate CH 4 2 (l) Well testing venting and flaring. 4 2 4 2 2 (1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested. (2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (ii) of this section to determine GOR. (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) You may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using equation W-17A to this section (for oil wells) or equation W-17B to this section (for gas wells) for each well tested during the reporting year. Where: E a,n GOR = Gas to oil ratio in cubic feet of gas per barrel of oil for each well being tested; oil here refers to hydrocarbon liquids produced of all API gravities. FR = Average annual flow rate in barrels of oil per day for the oil well being tested. PR = Average annual production rate in actual cubic feet per day for the gas well being tested. D = Number of days during the calendar year that the well is tested. (4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (5) Calculate both CH 4 2 (m) Associated gas venting and flaring. 4 2 4 2 2 (1) If you measure the gas flow to a vent using a continuous flow measurement device, you must use the measured flow volumes to calculate vented associated gas emissions. (2) If you do not measure the gas flow to a vent using a continuous flow measurement device, you must follow the procedures in paragraphs (m)(2)(i) through (iii) of this section. (i) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category. (ii) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraph (m)(2)(ii)(A) or (B) of this section to determine GOR. (A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (B) You may use an industry standard practice as described in § 98.234(b). (iii) Estimate venting emissions using equation W-18 to this section. Where: E s,n,p GOR p V p SG p (3) Calculate both CH 4 2 (n) Flare stack emissions. 2 4 2 (1) Destruction efficiency and combustion efficiency. 4 (i) Tier 1 (A) The applicable testing requirements in § 63.645(a), (b), (c), (d), and (i) of this chapter, including § 63.116 (a)(2), (3), (b), and (c) of this chapter. When § 63.645 refers to “organic HAP,” the terms “methane” and “CO 2 (B) The applicable monitoring requirements in § 63.644(a), (b), (d), and (e) of this chapter. The data to submit in a Notification of Compliance Status report in § 63.644(d) of this chapter shall be maintained as records for the purposes of this section (n)(1)(i), and references to violations in § 63.644(e) of this chapter do not apply for the purposes of this section (n)(1)(i). (C) The requirements in § 63.670 (a) through (n), § 63.670(p), and § 63.671 of this chapter. (ii) Tier 2 (A) The requirements in § 60.5412b(a)(1) of this chapter, along with the applicable testing requirements in § 60.5413b(b) of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter. (B) The requirements in § 60.5412b(a)(3) of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter. (C) If using an enclosed combustion device tested by the manufacturer in accordance with § 60.5413b(d) of this chapter, the requirements in § 60.5413b(b)(5)(iii) and (e) of this chapter, the applicable continuous compliance requirements in § 60.5415b(f) of this chapter, and the applicable continuous monitoring requirements in § 60.5417b of this chapter. You must also keep the applicable records in § 60.5420b(c)(11) of this chapter. (D) If you are subject to an approved state plan or applicable Federal plan in part 62 of this chapter that requires the reduction of methane by 95 percent, you may follow all applicable requirements of the approved state plan or applicable Federal plan in part 62 of this chapter, including the testing, continuous compliance, continuous monitoring, and recordkeeping requirements. (iii) Tier 3. (iv) Alternative test method. (v) Alternative destruction and combustion efficiencies. (A) Measure the combustion efficiency in accordance with an alternative test method approved in accordance with § 60.5412b(d) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. (B) Conduct monitoring as specified in §§ 60.5415b(f)(1)(x) and (xi) and 60.5417b(i) of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. (C) Adhere to all conditions in the monitoring plan you prepare as specified in § 60.5417b(i)(2) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter at all times. (D) You must use a destruction efficiency equal to the combustion efficiency plus 1.5. (E) If you fail to fully conform with your plan for a period of 15 or more consecutive days, you must utilize the Tier 3 default destruction and combustion efficiency values until such time that full conformance is achieved. You must document these periods and maintain records as specified in § 98.237 of the date when the non-conformance began, and the date when full conformance is re-established. (2) Pilot (i) At least once every five minutes monitor for the presence of a pilot flame or combustion flame using a device (including, but not limited to, a thermocouple, ultraviolet beam sensor, infrared sensor, video surveillance system, or advanced remote monitoring method) capable of detecting that the pilot or combustion flame is present at all times. (A) Monitoring for the presence of a flare flame in accordance with § 60.5417b satisfies the requirement of this paragraph (n)(2). (B) You may use multiple or redundant monitoring devices. When a discrepancy occurs between multiple devices, you must either visually confirm or use video surveillance output to confirm that the flame is present as soon as practicable after detecting the discrepancy to ensure that at least one device is operating properly. If you confirm that at least one device is operating properly, you may rely on the properly operating device(s) to monitor the flame. (C) Continuous monitoring systems used for the presence of a pilot flame or combustion flame are not subject to a minimum accuracy requirement beyond being able to detect the presence or absence of a flame and are exempt from the calibration requirements of this part 98. (D) Track the length of time over all periods when the flare is unlit and calculate the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section. (E) If all continuous monitoring devices are out of service for more than one week, then visually inspect for the presence of a pilot flame or combustion flame at least once per week for the first 4 weeks that the monitoring devices are out of service or until at least one repaired or new device is operational, whichever period is shorter. If all continuous monitoring devices are out of service for less than one week, then at least one visual inspection must be conducted during the outage. If a flame is not detected during a weekly visual inspection, assume the pilot has been unlit since the previous inspection or the last time the continuous monitoring device detected a flame, and assume that the pilot remains unlit until a subsequent inspection or continuous monitoring device detects a flame. If the monitoring device outage lasts more than 4 weeks, then you may switch to conducting inspections at least once per month in accordance with paragraph (n)(2)(ii) of this section. (ii) As an alternative to continuous monitoring as specified in paragraph (n)(2)(i) of this section, if you comply with tier 3 in paragraph (n)(1)(iii) of this section, at least once per month visually inspect for the presence of a pilot flame or combustion flame. You may also conduct visual inspections when using an alternative test method in accordance with paragraph (n)(1)(iv) of this section that allows visual inspections. If a flame is not detected, track the time since the previous inspection until a subsequent inspection detects a flame, and use this time in your calculation of the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section. Use the sum of the measured flows, as determined from measurements obtained under paragraph (n)(1) of this section, during all time periods when the pilot was determined to be unlit, to calculate the fraction of the total annual volume that is routed to the flare when it is unlit. (iii) For a flare subject to 40 CFR part 60 subpart OOOOb, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, a flare inspection conducted using an OGI camera during a fugitive emissions survey in accordance with § 60.5415b(f)(1)(x) constitutes a pilot flame inspection under this subpart. If a flame is not detected, track the time from the previous inspection until a subsequent inspection or continuous monitoring device detects a flame and use this time in your calculation of the fraction of the total flow to the flare that was routed to the flare when the flare was unlit as specified in paragraph (n)(2)(iv) of this section. (iv) If you measure total flow to the flare in accordance with paragraph (n)(3)(i) of this section, calculate the fraction of the total annual volume that is routed to the flare when it is unlit using the actual flow during the unlit time periods that are tracked according to paragraph (n)(2)(i)(D), (ii), or (iii) of this section. If you determine flows of individual streams routed to the flare in accordance with paragraph (n)(3)(ii) of this section, use the stream-specific average flow rates for the streams routed to the flare during unlit times to calculate the fraction of the total annual volume that is routed to the flare when it is unlit. (3) Flow determination. (i) Use a continuous parameter monitoring system to measure flow of gas to the flare downstream of any sweep, purge, or auxiliary gas addition. You may use either flow meters or indirectly calculate flow using other parameter monitoring systems combined with engineering calculations, such as line pressure, line size, and burner nozzle dimensions. If you use a continuous parameter monitoring system, you must use the measured flow in calculating the total flow volume to the flare. The continuous parameter monitoring system must measure data values at least once every hour. (ii) Determine flow to the flare from individual sources, including sweep, purge, auxiliary fuel, and collective flow from offsite sources that route gas to the flare using any combination of the methods in paragraphs (n)(3)(ii)(A) and (B) of this section, as applicable. Adjust the volumes determined as specified in paragraphs (n)(3)(ii)(A) and (B) of this section by any estimated bypass volumes diverted from entering the flare and leaks from the closed vent system in accordance with paragraphs (n)(3)(ii)(C) and (D) of this section. Do not adjust the volumes routed to the flare for volumes diverted through bypass lines located upstream of the flow measurement or determination location. (A) Use a continuous flow meter to measure the flow of gas from individual sources (or combination of sources) that route gas to the flare. If the emission streams for multiple sources are routed to a manifold before being combined with other emission streams, you may conduct the measurement in the manifold instead of from each source that is routed to the manifold. If you use a continuous flow meter, you must use the measured flow in calculating the total flow volume to the flare. The continuous flow meter must measure data values at least once every hour. (B) If flow from a source is not measured using a continuous flow meter, then use methods specified in paragraphs (n)(3)(ii)(B)(1) through ( 8 ( 1 8 ( 2 8 ( 3 ( 4 ( 5 8 ( 6 ( 7 ( 8 1 2 (C) If the closed vent system that routes emissions to the flare contains one or more bypass devices that could be used to divert all or a portion of the gases from entering the flare, then you must determine when flow is diverted through the bypass and estimate the volume that bypasses the flare. The bypass volume may be determined based on engineering calculations, process knowledge, and best available data. Use the estimated bypass volume to adjust the volumes determined in accordance with paragraph (n)(3)(ii)(A) or (B) of this section to determine the flow to the flare. For bypass volumes that are diverted directly to atmosphere, use the estimated volume in the calculation and reporting of vented emissions from the applicable source(s). (D) If you determine a component in the closed vent system is leaking, you must adjust the flow determined in accordance with paragraph (n)(3)(ii)(A) or (B) of this section by the estimated volume of the leak to determine the flow to the flare. Estimate the leak volume based on engineering calculations, process knowledge, and best available data. Report the estimated leak volume as vented emissions from the applicable source(s). (4) Gas composition. (i) Use a continuous gas composition analyzer on the inlet gas to the flare burner downstream of any purge, sweep, or auxiliary fuel addition to measure annual average mole fractions of methane, ethane, propane, butane, pentanes plus, and CO 2 (ii) Take samples of the inlet gas to the flare burner downstream of any purge, sweep, or auxiliary fuel addition at least annually in which gas is routed to the flare and analyze for methane, ethane, propane, butane, pentanes plus, and CO 2 (iii) When composition is not determined at the inlet to the flare as specified in either paragraph (i) or (ii) of this section, then determine annual average compositions for streams from individual sources (or combinations of sources), including sweep, purge, and auxiliary fuel, routed to the flare using any combination of the methods specified in paragraphs (n)(4)(iii)(A) and (B) of this section, as applicable. (A) Use a continuous gas composition analyzer to measure annual average mole fractions of methane, ethane, propane, butane, pentanes plus, and CO 2 (B) If composition is not measured in accordance with paragraph (n)(4)(iii)(A) of this section, then use methods specified in paragraphs (n)(4)(iii)(B)( 1 7 1 5 1 5 ( 1 ( 2 5 ( 3 5 ( 4 ( 5 6 1 4 7 ( 6 ( 7 (5) Calculate CH 4 and CO 2 emissions Where: E s,CH 4 4 E s,CO 2 2 V s ηD = Flare destruction efficiency, expressed as fraction of hydrocarbon compounds in gas that is destroyed by a burning flare, but may or may not be completely oxidized to CO 2 ηC = Flare combustion efficiency, expressed as fraction of hydrocarbon compounds in gas that is oxidized to CO 2 X CH 4 4 X CO 2 2 ZU = Fraction of the feed gas sent to an un-lit flare determined from both the total time the flare was unlit as determined by monitoring the pilot flame or combustion flame as specified in paragraph (n)(2) of this section and the volume of gas routed to the flare during periods when the flare was unlit based on the flow determined in accordance with paragraph (n)(3) of this section. Z L Y j R j (i) If you measure the gas flow at the flare inlet as specified in paragraph (n)(3)(i) of this section and you measure gas composition for the inlet gas to the flare as specified in paragraph (n)(4)(i) or (ii) of this section, then use those data in equations W-19 and W-20 to this section to calculate total emissions from the flare. (ii) If you determine the flow from each source as specified in paragraph (n)(3)(ii) of this section and you measure gas composition for the inlet gas to the flare as specified in paragraph (n)(4)(i) or (ii) of this section, then sum the flows for each stream to calculate the total annual gas flow to the flare. Use that total annual flow with the annual average concentration of each constituent as calculated in paragraph (n)(4)(i) or (ii) of this section in equations W-19 and W-20 to this section to calculate total emissions from the flare. (iii) If you determine the flow from each source as specified in paragraph (n)(3)(ii) of this section and you determine gas composition for the emission stream from each source as specified in paragraph (n)(4)(iii) of this section, then calculate total emissions from the flare as specified in either paragraph (n)(5)(iii)(A) or (B) of this section. (A) Use each set of stream-specific flow and annual average concentration data in equations W-19 and W-20 to this section to calculate stream-specific flared emissions for each stream, and then sum the results from each stream-specific calculation to calculate the total emissions from the flare. (B) Sum the flows from each source to calculate the total gas flow into the flare and use the source-specific flows and source-specific annual average concentrations to determine flow-weighted annual average concentrations of CO 2 (iv) You may not combine measurement of the inlet gas flow to the flare as specified in paragraph (n)(3)(i) of this section with measurement of the gas composition of the streams from each source as specified in paragraph (n)(4)(iii) of this section. (6) Convert volume at actual conditions to volume at standard conditions. (7) Convert volumetric emissions to mass emissions 4 2 (8) Calculate N 2 O emissions. 2 (i) Directly measure the annual average higher heating value in the inlet stream to the flare using either a continuous gas composition analyzer or a calorimeter. Use this flare-specific annual average higher heating value for the parameter “HHV” in equation W-40 to this section, and use either the total inlet flow to the flare measured as specified in paragraph (n)(3)(i) of this section or the sum of the flows of individual streams routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate the total N 2 (ii) Calculate the annual average higher heating value in the inlet stream to the flare using annual average gas compositions of the inlet stream measured in accordance with paragraph (n)(4)(i) or (ii) of this section. Use this flare-specific annual average higher heating value for the parameter “HHV” in equation W-40 to this section, and use either the total inlet flow to the flare measured as specified in paragraph (n)(3)(i) of this section or the sum of the flows of individual streams routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate the total N 2 (iii) Directly measure the annual average higher heating values in the individual streams routed to the flare using either a continuous gas composition analyzer or a calorimeter. Calculate the total N 2 (A) Use the stream-specific annual average higher heating values for the parameter “HHV” in equation W-40 to this section, use the stream-specific flows as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section in separate stream-specific calculations of N 2 2 (B) Use the stream-specific annual average higher heating values and flows to calculate a flow-weighted annual average higher heating value to use as the parameter “HHV” in equation W-40 to this section and the sum of the individual stream flows routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate total N 2 (iv) Calculate annual average higher heating values for the individual streams routed to the flare using gas compositions determined in accordance with paragraph (n)(4)(iii) of this section. Calculate the total N 2 (A) Use the stream-specific annual average higher heating values and the stream-specific flows in separate stream-specific calculations of N 2 2 (B) Use the stream-specific annual average higher heating values and flows to calculate a flow-weighted annual average higher heating value to use as the parameter “HHV” in equation W-40 to this section and the sum of the individual stream flows routed to the flare as determined in paragraph (n)(3)(ii) of this section for the parameter “Fuel” in equation W-40 to this section to calculate total N 2 (9) CEMS. 2 2 2 2 (10) Disaggregation. (i) Acid gas removal units. (ii) Dehydrators. (iii) Completions and workovers with hydraulic fracturing. (iv) Completions and workovers without hydraulic fracturing. (v) Hydrocarbon liquids and produced water storage tanks. (vi) Well testing. (vii) Associated gas. (viii) Other (collectively). (o) Centrifugal compressor venting. 4 2 4 2 4 2 2 (1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (o)(1)(i), (ii), (iii), or (iv) of this section. (i) Centrifugal compressor source as found measurements. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals. (B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (o)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (o)(2)(i) of this section, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section if the compressor has wet seal oil degassing vents, and measure volumetric emissions from dry seal vents as specified in paragraph (o)(2)(iii) of this section if the compressor has dry seals. (D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section. (ii) Centrifugal compressor source continuous monitoring. (iii) Manifolded centrifugal compressor source as found measurements. (A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the compressors are in any compressor mode. (iv) Manifolded centrifugal compressor source continuous monitoring. (2) Methods for performing as found measurements from individual centrifugal compressor sources (i) For blowdown valves on compressors in operating-mode or in standby-pressurized-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section. (A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). (C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods. (ii) For wet seal oil degassing vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions, using one of the methods specified in paragraphs (o)(2)(ii)(A) through (C) of this section. You must quantitatively measure the volumetric flow for wet seal oil degassing vent; you may not use screening methods set forth in § 98.234(a) to screen for emissions for the wet seal oil degassing vent. (A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b). (B) Use calibrated bags according to methods set forth in § 98.234(c). (C) Use a high volume sampler according to methods set forth in § 98.234(d). (iii) For dry seal vents in operating-mode or in standby-pressurized-mode, determine volumetric flow at standard conditions from each dry seal vent using one of the methods specified in paragraphs (o)(2)(iii)(A) through (D) of this section. The measurement should be conducted on the compressor side dry seal. If a compressor has more than one dry seal vent, determine the aggregate dry seal vent volumetric flow for the compressor as the sum of the volumetric flows determined for each dry seal vent on the compressor. (A) Use a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b). (B) Use calibrated bags according to methods set forth in § 98.234(c). (C) Use a high volume sampler according to methods set forth in § 98.234(d). (D) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraph (o)(2)(iii)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening dry seal vents. (3) Methods for continuous measurement from individual centrifugal compressor sources. (i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found measurements from manifolded groups of centrifugal compressor sources. (i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources. (ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (F) of this section. (A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (D) [Reserved] (E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these methods, then you must use one of the methods specified in paragraph (o)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources. (F) If one of the screening methods specified in § 98.234(a)(1) through (3) identifies a leak in a manifolded group of centrifugal compressor sources, you may use acoustic leak detection, according to § 98.234(a)(5), to identify the source of the leak. You must use one of the methods specified in paragraphs (o)(4)(ii)(A) through (D) of this section to quantify emissions from the identified source. (5) Methods for continuous measurement from manifolded groups of centrifugal compressor sources. (i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found measurements for individual centrifugal compressor sources (i) Using equation W-21 to this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was measured during the reporting year. Where: E s,i,m i 4 2 MT s,m T m GHG i,m i m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was measured for the reporting year. (ii) Using equation W-22 to this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section that was not measured during the reporting year. Where: E s,i,m i 4 2 EF s,m T m GHG i,m i m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section that was not measured in the reporting year. (iii) Using equation W-23 to this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (o)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in equation W-22 to this section to determine volumetric emissions from a centrifugal compressor in the mode- source combinations that were not measured in the reporting year. Where: EF s,m MT s,m,p s,m Count m m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A), (B), or (C) of this section.” (iv) The reporter emission factor in equation W-23 to this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources Where: E s,i,v i 4 2 Q s,v GHG i,v i (8) Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of centrifugal compressor sources Where: E s,i,g i 4 2 g s,g,avg GHG i,g i (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of centrifugal compressor sources. Where: E s,i,g i 4 2 Q s,g GHG i,g i (10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility. (i) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are subject to the centrifugal compressor standards in § 60.5380b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for dry seals and self-contained wet seals, you must conduct the volumetric emission measurements as required by § 60.5380b(a)(5) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, conduct all additional volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (o)(6) through (9) of this section. Conduct all measurements required by this paragraph (o)(10)(i) at the frequency specified by § 60.5380b(a)(4) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5380b(a)(4) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (o)(6)(ii) of this section. (ii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are not subject to the centrifugal compressor standards in § 60.5380b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for dry seals and self-contained wet seals, you may elect to conduct the volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (o)(6) through (9) of this section. (iii) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate total atmospheric wet seal oil degassing vent emissions from all centrifugal compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-25A to this section. Emissions from centrifugal compressor wet seal oil degassing vents that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (o). Where: E s,i i 4 2 Count = Total number of centrifugal compressors with wet seal oil degassing vents that are vented directly to the atmosphere. E s,i,p i 4 2 (iv) For all centrifugal compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (o)(10)(i) of this section does not apply, and you do not elect to conduct the volumetric measurements specified in paragraph (o)(1) of this section, you must calculate wet seal oil degassing vent emissions from each centrifugal compressor using equation W-25B to this section. Emissions from centrifugal compressor wet seal oil degassing vents that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (o). Where: E s,i,p i 4 2 EF s,p 4 2 T p T total GHG i,p 4 2 GHG EF 4 2 s,p 4 2 (11) Method for converting from volumetric to mass emissions 4 2 (p) Reciprocating compressor venting. 4 2 4 2 4 2 2 (1) General requirements for conducting volumetric emission measurements. (i) Reciprocating compressor source as found measurements. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable. (B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in paragraph (p)(2)(i) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (C) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in paragraph (p)(2)(i) of this section and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section, as applicable. (D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section. (ii) Reciprocating compressor source continuous monitoring. (iii) Manifolded reciprocating compressor source as found measurements. (A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year. (B) The measurement may be performed while the compressors are in any compressor mode. (iv) Manifolded reciprocating compressor source continuous monitoring. (2) Methods for performing as found measurements from individual reciprocating compressor sources (i) For blowdown valves on compressors in operating-mode or standby-pressurized-mode, (A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively. (B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraphs (p)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. (ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode or standby-pressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(ii)(A) through (C) of this section. (A) Determine the volumetric flow at standard conditions from the open-ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively. (B) Determine the volumetric flow at standard conditions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (C) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraphs (p)(2)(ii)(A) and (B) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C), when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening or measuring rod packing emissions. (iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determine the volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (B) of this section. (A) You must use the methods described in § 98.234(a)(1) through (3) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening rod packing emissions. (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. (3) Methods for continuous measurement from individual reciprocating compressor sources (i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found measurements from manifolded groups of reciprocating compressor sources (i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources. (ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (p)(4)(ii)(A) through (F) of this section. (A) A temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). (C) A high volume sampler according to methods set forth in § 98.234(d). (D) [Reserved] (E) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using one of these specified methods, then you must use one of the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method. Acoustic leak detection is only applicable for through-valve leakage and is not applicable for screening a manifolded group of compressor sources. (F) If one of the screening methods specified in § 98.234(a)(1) through (3) identifies a leak in a manifolded group of reciprocating compressor sources, you may use acoustic leak detection, according to § 98.234(a)(5), to identify the source of the leak. You must use one of the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this section to quantify the emissions from the identified source. (5) Methods for continuous measurement from manifolded groups of reciprocating compressor sources (i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found measurements for individual reciprocating compressor sources (i) Using equation W-26 to this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was measured during the reporting year. Where: E s,i,m i 4 2 MT s,m T m GHG i,m i m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section that was measured for the reporting year. (ii) Using equation W-27 to this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was not measured during the reporting year. Where: E s,i,m i 4 2 EF s,m T m GHG i,m i m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured for the reporting year. (iii) Using equation W-28 to this section, develop an emission factor for each compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section. These emission factors must be calculated annually and used in equation W-27 to this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year. Where: EF s,m MT s,m,p s,m Count m m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), or (C) of this section. (iv) The reporter emission factor in equation W-28 to this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources Where: E s,i,v i 4 2 Q s,v GHG i,v i (8) Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of reciprocating compressor sources. Where: E s,i,g i 4 2 T g MT s,g,avg GHG i,g i (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources Where: E s,i,g i 4 2 Q s,g GHG i,g i (10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility (i) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are subject to the reciprocating compressor standards in § 60.5385b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must conduct the volumetric emission measurements as required by § 60.5385b(b) and (c) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, conduct any additional volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (p)(6) through (9) of this section. Conduct all measurements required by this paragraph (p)(10)(i) at the frequency specified by § 60.5385b(a) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. For any reporting year in which measuring at the frequency specified by § 60.5385b(a) of this chapter results in measurement not being required for a subject compressor, calculate emissions for all mode-source combinations as specified in paragraph (p)(6)(ii) of this section. (ii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility that are not subject to the reciprocating compressor standards in § 60.5385b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section (based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement), and calculate emissions as specified in paragraphs (p)(6) through (9) of this section. (iii) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, and you do not elect to conduct volumetric emission measurements specified in paragraph (p)(1) of this section, you must calculate total atmospheric rod packing emissions from all reciprocating compressors at either an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using equation W-29D to this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (p). Where: E s,i i 4 2 Count = Total number of reciprocating compressors with rod packing emissions vented directly to the atmosphere. E s,i,p i 4 2 (iv) For all reciprocating compressors at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility for which paragraph (p)(10)(i) of this section does not apply, you must calculate rod packing vent emissions from each reciprocating compressor using equation W-29E to this section. Reciprocating compressor rod packing emissions that are routed to a flare, combustion, or vapor recovery system are not required to be determined under this paragraph (p). Where: E s,i,p i 4 2 EF s,p 5 4 4 2 T p s,i,p T total GHG i,p 4 2 GHG EF 4 2 s,p 4 2 (11) Method for converting from volumetric to mass emissions. 4 2 (q) Equipment leak surveys. 4 2 4 2 (1) Survey requirements (ii) For the components listed in § 98.232(i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a) except § 98.234(a)(2)(ii) and calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. (iii) For the components listed in § 98.232(c)(21)(i), (e)(7) and (8), (f)(5) through (8), (g)(4), (g)(6) and (7), (h)(5), (h)(7) and (8), and (j)(10)(i) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, and are required to conduct surveys using any of the leak detection methods in § 98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, you must use the results of those surveys to calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. (iv) For the components listed in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), that are not subject to or are not required to conduct surveys using the methods in § 98.234(a) in accordance with the fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a). (A) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the procedures in either paragraph (q)(2) or (3) of this section. (B) If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(e)(8), (f)(6) and (8), (g)(7), and (h)(8), then you must use the procedures in either paragraph (q)(2) or (3) of this section to calculate those emissions. (C) If you elect to use a leak detection method in § 98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, for any elective survey under paragraph (q)(1)(iv) of this section, then you must survey the component types in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) that are not subject to or are not required to conduct surveys using the methods in § 98.234(a) in accordance with the fugitive emissions standards in § 60.5397a of this chapter, the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b or 60.5398b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21)(i), (e)(8), (f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) using the emission calculation requirements in either paragraph (q)(2) or (3) of this section. (v) For the components listed in § 98.232(d)(7), you must conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this section and you must calculate equipment leak emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. (A) For the components listed in § 98.232(d)(7) that are not subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you may use any of the leak detection methods listed in § 98.234(a). (B) For the components listed in § 98.232(d)(7) that are subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter, or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must use either of the leak detection methods in § 98.234(a)(1)(iii) or (a)(2)(ii). (vi) For the components listed in § 98.232(m)(3)(ii) and (m)(4)(ii), you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a). If you elect to use a leak detection method in § 98.234(a) for the surveyed component types in § 98.232(m)(3)(ii) and (m)(4)(ii) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(m)(3)(ii) and (m)(4)(ii) using the procedures in either paragraph (q)(2) or (3) of this section. (vii) Except as provided in paragraph (q)(1)(viii) of this section, you must conduct at least one complete leak detection survey in a calendar year. If you conduct multiple complete leak detection surveys in a calendar year, you must use the results from each complete leak detection survey when calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. Except as provided in paragraphs (q)(1)(vii)(A) through (H) of this section, a complete leak detection survey is a survey in which all equipment components required to be surveyed as specified in paragraphs (q)(1)(i) through (vi) of this section are surveyed. (A) For components subject to the well site and compressor station fugitive emissions standards in § 60.5397a of this chapter, each survey conducted in accordance with § 60.5397a of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section. (B) For components subject to the well site, centralized production facility, and compressor station fugitive emissions standards in § 60.5397b or 60.5398b of this chapter, each survey conducted in accordance with the fugitive emissions standards for well sites, centralized production facilities, and compressor stations in § 60.5397b, 60.5398b(b)(4) or 60.5398b(b)(5)(ii) of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section. (C) For components subject to the well site, centralized production facility, and compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with the applicable approved state plan or applicable Federal plan in part 62 of this chapter using one of the methods in § 98.234(a) will be considered a complete leak detection survey for purposes of this section. (D) For an onshore petroleum and natural gas production facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a single well-pad site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section. (E) For an onshore petroleum and natural gas gathering and boosting facility electing to conduct leak detection surveys according to paragraph (q)(1)(iv) of this section, a survey of all required components at a gathering and boosting site, as defined in § 98.238, will be considered a complete leak detection survey for purposes of this section. (F) For an onshore natural gas processing facility subject to the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, each survey conducted in accordance with the equipment leak standards for onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter will be considered a complete leak detection survey for the purposes of calculating emissions using the procedures specified in either paragraph (q)(2) or (3) of this section. At least one complete leak detection survey conducted during the reporting year must include all components listed in § 98.232(d)(7) and subject to this paragraph (q), including components which are considered difficult-to-monitor emission sources as specified in § 98.234(a). Inaccessible components as provided in §§ 60.5401b(h)(3) and 60.5401c(h)(3) of this chapter are exempt from the monitoring requirements in this subpart. (G) For natural gas distribution facilities that choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years as provided in paragraph (q)(1)(viii) of this section, a survey of all required components at the above grade transmission-distribution transfer stations monitored during the calendar year will be considered a complete leak detection survey for purposes of this section. (H) For onshore natural gas transmission pipeline facilities that conduct leak detection surveys according to paragraph (q)(1)(vi) of this section, a survey of all required components at a transmission company interconnect metering-regulating station or a farm tap/direct sale metering-regulating station, will be considered a complete leak detection survey for purposes of this section. (viii) Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform equipment leak surveys under this section. Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years “n,” not exceeding a five-year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the number of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle. (2) Calculation Method 1: Leaker emission factor calculation methodology. Where: E s,p,i i x p EF s,p k = Factor to adjust for undetected leaks by respective leak detection method, where k equals 1.25 for the methods in § 98.234(a)(1), (3) and (5); k equals 1.55 for the method in § 98.234(a)(2)(i); and k equals 1.27 for the method in § 98.234(a)(2)(ii). GHG i i 4 2 i 4 2 i 4 −2 2 i 4 2 i 4 2 i 4 −2 2 T p,z i.e., (i) The leak detection surveys selected for use in equation W-30 to this section must be conducted during the calendar year as indicated in paragraph (q)(1)(vii) and (viii) of this section, as applicable. (ii) Calculate both CO 2 4 (iii) Onshore petroleum and natural gas production facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default whole gas leaker emission factors consistent with the well type, where components associated with gas wells are considered to be in gas service and components associated with oil wells are considered to be in oil service as listed in table W-2 to this subpart. (iv) Onshore petroleum and natural gas gathering and boosting facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default whole gas leaker factors for components in gas service listed in table W-2 to this subpart. (v) Onshore natural gas processing facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in table W-4 to this subpart. (vi) Onshore natural gas transmission compression facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in table W-4 to this subpart. (vii) Underground natural gas storage facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default total hydrocarbon leaker emission factors for storage stations or storage wellheads in gas service listed in table W-4 to this subpart. (viii) LNG storage facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default methane leaker emission factors for LNG storage components in LNG service or gas service listed in table W-6 to this subpart. (ix) LNG import and export facilities must, if available, use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of section or use the appropriate default methane leaker emission factors for LNG terminals components in LNG service or gas service listed in table W-6 to this subpart. (x) Except as provided in paragraph (q)(3)(viii) of this section, natural gas distribution facilities must use equation W-30 to this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in table W-6 to this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-distribution transfer stations. (A) Use equation W-31 to this section to determine the meter/regulator run population emission factors for each GHG i i Where: EF s,MR,i i i E s,p,i,y i p = Seven component types listed in table W-6 to this subpart for transmission-distribution transfer stations. T w,y Count MR,y y = Year of data included in emission factor “EF s,MR,i n = Number of years of data, according to paragraph (q)(1)(viii) of this section, whose results are used to calculate emission factor “EF s,MR,i (B) The emission factor “EF s,MR,i s,MR,i s,MR,i s,MR,i new s,MR,i new (xi) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section, you must use the meter/regulator run population emission factors calculated using equation W-31 to this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using equation W-32B to this section. (xii) Onshore natural gas transmission pipeline facilities must use the facility-specific leaker emission factor calculated in accordance with paragraph (q)(4) of this section. (3) Calculation Method 2: Leaker measurement methodology. (i) Determine the volumetric flow rate of each natural gas leak identified during the leak survey following the methods § 98.234(b) through (d), as appropriate for each leak identified. You do not need to use the same measurement method for each leak measured. If you are unable to measure the natural gas leak because it would require elevating the measurement personnel more than 2 meters above the surface and a lift is unavailable at the site or it would pose immediate danger to measurement personnel, then you must substitute the default leak rate for the component and site type from tables W-2, W-4, or W-6 to this subpart, as applicable, as the measurement for this leak. (ii) For each leak, calculate the volume of natural gas emitted as the product of the natural gas flow rate measured in paragraph (q)(3)(i) of this section and the duration of the leak. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year. If multiple leak detection surveys are conducted in the calendar year, assume a component found leaking in the first survey was leaking since the beginning of the year until the date of the survey; assume a component found leaking in the last survey of the year was leaking from the preceding survey through the end of the year; assume a component found leaking in a survey between the first and last surveys of the year was leaking since the preceding survey until the date of the survey. For each leaking component, account for time the component was not operational ( i.e. (iii) For each leak, convert the volumetric emissions of natural gas determined in paragraph (q)(3)(ii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section. (iv) For each leak, convert the volumetric emissions of natural gas at standard conditions determined in paragraph (q)(3)(iii) of this section to CO 2 4 (v) For each leak, convert the GHG volumetric emissions at standard conditions determined in paragraph (q)(3)(iv) of this section to GHG mass emissions using the methods specified in paragraph (v) of this section. (vi) Sum the CO 2 4 (vii) Multiply the total CO 2 4 (viii) For natural gas distribution facilities: (A) Use equation W-31 to this section to determine the meter/regulator run population emission factors for each GHG i (B) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(1)(viii) of this section, you must use the meter/regulator run population emission factors calculated according to paragraph (q)(3)(viii)(A) of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using equation W-32B to this section. (4) Development of facility-specific component-level leaker emission factors by leak detection method. (i) You must track the leak measurements made separately for each of the applicable components listed in paragraphs (q)(1)(i) through (vi) of this section and by the leak detection method according to the following three bins. (A) Method 21 as specified in § 98.234(a)(2)(i). (B) Method 21 as specified in § 98.234(a)(2)(ii). (C) Optical gas imaging (OGI) and other leak detection methods as specified in § 98.234(a)(1), (3), or (5). (ii) You must accumulate a minimum of 50 leak measurements total for a given component type and leak detection method combination before you can develop and use a facility-specific component-level leaker emission factor for use in calculating emissions according to paragraph (q)(2) of this section (Calculation Method 1: Leaker emission factor calculation methodology). (iii) Sum the volumetric flow rate of natural gas determined in accordance with paragraph (q)(3)(i) of this section for each leak by component type and leak detection method as specified in paragraph (q)(4)(i) of this section meeting the minimum number of measurement requirement in paragraph (q)(4)(ii) of this section. (iv) Convert the volumetric flow rate of natural gas determined in paragraph (q)(4)(iii) of this section to standard conditions using the method specified in paragraph (t)(1) of this section. (v) Determine the emission factor in units of standard cubic feet per hour component (scf/hr-component) by dividing the sum of the volumetric flow rate of natural gas determined in paragraph (q)(4)(iv) of this section by the total number of leak measurements for that component type and leak detection method combination. (vi) You must update the emission factor determined in (q)(4)(v) of this section annually to include the results from all complete leak surveys for which leak measurement was performed during the reporting year in accordance with paragraph (q)(3) of this section. (r) Equipment leaks by population count. 4 2 4 2 Where: E s,e,i i e.g., e.g., E s,MR,i i i Count e Count MR EF s,e EF s,MR,i i i GHG i i 4 2 i 4 −2 2 i 4 2 i 4 2 i 4 −2 2 T e T w,avg (1) Calculate both CH 4 2 (2) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas population emission factors listed in table W-1 to this subpart. Major equipment associated with gas wells are considered gas service equipment in table W-1 to this subpart. Onshore petroleum and natural gas gathering and boosting facilities shall use the gas service equipment emission factors in table W-1 to this subpart. Major equipment associated with crude oil wells are considered crude service equipment in table W-1 to this subpart. Where facilities conduct EOR operations, the emission factor listed in table W-1 to this subpart shall be used to estimate all streams of gases, including recycle CO 2 (3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in table W-3 to this subpart. (4) LNG storage facilities must use the appropriate default methane population emission factors for LNG storage compressors in gas service listed in table W-5 to this subpart. (5) LNG import and export facilities must use the appropriate default methane population emission factors for LNG terminal compressors in gas service listed in table W-5 to this subpart. (6) Natural gas distribution facilities must use the appropriate methane emission factors as described in paragraphs (r)(6)(i) and (ii) of this section. (i) Below grade transmission-distribution transfer stations, below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in table W-5 to this subpart to estimate emissions from components listed in § 98.232(i)(2), (4), (5), and (6), respectively. (ii) Above grade metering-regulating stations that are not above grade transmission-distribution transfer stations must use the meter/regulator run population emission factor calculated in equation W-31 to this section in accordance with paragraph (q)(2)(x) or (q)(3)(viii)(A) of this section for the components listed in § 98.232(i)(3). Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required to report GHG emissions in § 98.236(r)(2)(v). (7) Onshore natural gas transmission pipeline facilities must use the appropriate default methane population emission factors listed in table W-5 to this subpart to estimate emissions from components listed in § 98.232(m)(3)(i), (4)(i) and (5). (s) Offshore petroleum and natural gas production facilities 2 4 2 i.e., (1) Offshore production facilities that report to BOEM's emissions inventory must calculate emissions as specified in paragraph (s)(1)(i) or (ii) of this section, as applicable. (i) Report the same annual emissions calculated using the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304 for any reporting year that overlaps with a BOEM emissions inventory year and any other reporting year in which the BOEM's emissions reporting system is available and the facility has the data needed to use BOEM's emissions reporting system. (ii) If BOEM's emissions reporting system is not available or if the facility does not have the data needed to use BOEM's emissions reporting system, adjust emissions from the most recent emissions calculated in accordance with paragraph (s)(1)(i), (s)(3), or (s)(4) of this section, as applicable, by using a ratio of the operating time for the facility in the current reporting year relative to the operating time for the facility during the reporting year for which emissions were calculated as specified in paragraph (s)(1)(i), (s)(3), or (s)(4) of this section, as applicable. (2) Offshore production facilities that do not report to BOEM's emissions inventory must calculate emissions as specified in paragraph (s)(2)(i) or (ii) of this section, as applicable. (i) Use the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304 to calculate annual emissions for any reporting year that overlaps with a BOEM emissions inventory year and any other reporting year in which the facility has the data needed to use BOEM's emissions calculation methods. (ii) If the facility does not have the data needed to use BOEM's calculation methods, adjust emissions from the facility's most recent emissions calculated in accordance with paragraph (s)(2)(i), (s)(3), or (s)(4) of this section, as applicable, by using a ratio of the operating time for the facility in the current reporting year relative to the operating time for the facility in the reporting year for which the emissions were calculated as specified in paragraph (s)(2)(i), (s)(3), or (s)(4) of this section, as applicable. (3) If BOEM's emissions inventory is discontinued or delayed for more than 3 consecutive years, then offshore production facilities shall once in every 3 years use the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate annual emissions for each of the emission source types covered in BOEM's most recently published calculation methods. (4) For the first year of reporting, offshore production facilities must use the most recent monitoring and calculation methods published by BOEM referenced in 30 CFR 550.302 through 304 to calculate and report annual emissions. (t) GHG volumetric emissions using actual conditions. (1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and equation W-33 to this section for conversions of E a,n a Where: E s,n s,n s,p E a,n a,n a,p T s T a P s P a Z a (2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and equation W-34 to this section. Where: E s,i E a,i T s T a P s P a Z a i (3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert volumetric emissions from 68 °F to 60 °F. (u) GHG volumetric emissions at standard conditions. (1) Estimate CH 4 2 Where: E s,i 4 2 E s,n M i (2) For equation W-35 to this section, the mole fraction, M i (i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities. (ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment and the onshore natural gas transmission pipeline industry segment. (iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment. (v) GHG mole fraction in natural gas stored in the LNG storage industry segment. (vi) GHG mole fraction in natural gas stored in the LNG import and export industry segment. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. (v) GHG mass emissions. Where: Mass i i 4 2 2 E s,i i 4 2 2 ρ i i 3 2 2 3 4 (w) EOR injection pump blowdown. 2 (1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. (2) Retain logs of the number of blowdowns per calendar year. (3) Calculate the total annual CO 2 Where: Mass CO 2 N = Number of blowdowns for the EOR injection pump system in the calendar year. V v R c 3 GHG CO 2 2 1 × 10 −3 (x) EOR hydrocarbon liquids dissolved CO 2 2 2 (1) Determine the amount of CO 2 2 (2) Estimate emissions using equation W-38 to this section. Where: Mass CO 2 2 2 S hl 2 V hl (y) Other large release events. 2 4 (1) You must report emissions for other large release events that emit GHG at or above any applicable threshold listed in paragraphs (y)(1)(i) or (ii) of this section. You must report the emissions for the entire duration of the event, not just those time periods of the event emissions exceed the thresholds in paragraphs (y)(1)(i) or (ii) of this section. (i) For sources not subject to reporting under paragraphs (a) through (s), (w), (x), (dd), or (ee) of this section (such as but not limited to a fire, explosion, well blowout, or pressure relief), a release that emits methane at any point in time at a rate of 100 kg/hr or greater. (ii) For sources subject to reporting under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section, a release that emits methane at any point in time at a rate of 100 kg/hr or greater in excess of the emissions calculated from the source using the applicable methods under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section. For a release meeting the criteria in this paragraph (y)(1)(ii), you must report the emissions as an other large release event and exclude the emissions that would have been calculated for that source during the timespan of the event in the source-specific emissions calculated under paragraphs (a) through (h), (j) through (s), (w), (x), (dd), or (ee) of this section, as applicable. (2) Estimate the total volume of gas released during the event in standard cubic feet and the methane emission rate at any point in time during the event in kilograms per hour using measurement data according to § 98.234(b), if available, or a combination of process knowledge, engineering estimates, and best available data when measurement data are not available according to paragraphs (y)(2)(i) through (v) of this section. (i) The total volume of gas released must be estimated as the product of the measured or estimated average flow or release rate and the estimated event duration. For events for which information is available showing variable or decaying flow rates, you must calculate the maximum natural gas flow or release rate during the event and either determine a representative average release rate across the entire event or determine representative release rates for specific time periods within the event duration. If you elect to determine representative release rates for specific time periods within the event duration, calculate the volume of gas released for each time period within the event duration as the product of the representative release rate and the length of the corresponding time period and sum the volume of gas released across each of the time periods for the full duration of the event. For events that have releases from multiple release points but have a common root cause ( e.g. (ii) The start time of the event must be determined based on monitored process parameters and sound engineering principles. If monitored process parameters cannot identify the start of the event, the event must be assumed to start on the date of the most recent monitoring or measurement survey that confirms the source was not emitting at or above the rates specified in paragraph (y)(1) of this section or assumed to have started 91 days prior to the date the event was first identified, whichever start date is most recent. (iii) The end time of the event must be the date of the confirmed repair or confirmed cessation of emissions. (iv) For the purposes of paragraph (y)(2)(ii) of this section, “monitoring or measurement survey” includes any monitoring or measurement method in § 98.234(a) through (d) as well as advanced screening methods such as monitoring systems mounted on vehicles, drones, helicopters, airplanes, or satellites capable of identifying emissions at the thresholds specified in paragraph (y)(1) of this section at a 90 percent probability of detection as demonstrated by controlled release tests. Audio, visual, and olfactory inspections are considered monitoring surveys if and only if the event was identified via an audio, visual, and olfactory inspection. (v) For events that span two different reporting years, calculate the portion of the event's volumetric emissions calculated according to paragraph (y)(2)(i) of this section that occurred in each reporting year considering only reporting year 2025 and later reporting years. For events with consistent flow or for which one average emissions rate is used, use the relative duration of the event within each reporting year to apportion the volume of gas released for each reporting year. For variable flow events for which the volume of gas released is estimated for separate time periods, sum the volume of gas released across each of the time periods within a given reporting year separately. If one of the time periods span two different reporting years, calculate the portion of the volumetric emissions calculated for that time period that applies to each reporting year based on the number of hours in that time period within each reporting year. (3) Determine the composition of the gas released to the atmosphere using measurement data, if available, or a combination of process knowledge, engineering estimates, and best available data when measurement data are not available. In the event of an explosion or fire, where a portion of the natural gas may be combusted, estimate the composition of the gas released to the atmosphere considering the fraction of natural gas released directly to the atmosphere and the fraction of natural gas that was combusted by the explosion or fire during the release event. Assume combustion efficiency equals destruction efficiency and assume a maximum combustion efficiency of 92 percent for natural gas that is combusted in an explosion or fire when estimating the CO 2 4 e.g. (4) Calculate the GHG volumetric emissions using equation W-35 to this section. (5) Calculate both CH 4 2 (6) If you receive an EPA-provided notification under the super emitter program in § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, you must include the emissions from that source or event within your subpart W report unless you can provide certification as specified in either paragraph (y)(6)(i) or (ii) of this section, as applicable, or unless the EPA has determined that the notification has a demonstrable error, as specified in paragraph (y)(6)(iii) of this section. (i) If you do not own or operate any petroleum and natural gas system equipment within 50 meters of the location identified in the notification, you may prepare and submit the certification that the facility does not own or operate the equipment at the location identified in the notification. (ii) If you own or operate petroleum and natural gas system equipment within 50 meters of the location identified in the notification, but there are also other petroleum and natural gas system equipment within 50 meters of the location identified in the notification owned and operated by a different facility, you may prepare and submit the certification that the facility does not own or operate the emitting equipment at the location identified in the notification if and only if you comply with all of the following requirements. (A) Within 5 days of receiving the notification, complete an investigation of available data as specified in § 60.5371b(d)(2)(i) through (iv) of this chapter to identify the emissions source related to the event notification. (B) If the data investigation in paragraph (y)(6)(ii)(A) of this section does not identify the emissions source related to the event notification, you must conduct a complete survey of equipment at your facility that is within 50 meters of the location identified in the notification following any one of the methods provided in § 98.234(a)(1) through (3) within 15 days of receiving the notification. (C) The investigations and surveys conducted in paragraphs (y)(6)(ii)(A) and (B) of this section verify that none of the equipment that you own or operate at the location identified in the notification were responsible for the high emissions event. (iii) For consideration of demonstrable error, you must submit a statement of demonstrable error as specified by § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. You must report emissions associated with the notification unless the EPA has determined that the notification contained a demonstrable error. (z) Combustion equipment. 2 4 2 (1) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(1)(i) of this section, then calculate emissions according to paragraph (z)(1)(ii) of this section. (i) The fuel combusted in the stationary or portable equipment is listed in table C-1 to subpart C of this part or is a blend in which all fuels are listed in table C-1. If the fuel is natural gas or the blend contains natural gas, the natural gas must also meet the criteria of paragraphs (z)(1)(i)(A) and (B) of this section. (A) The natural gas must be of pipeline quality specification. (B) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot. (ii) For fuels listed in paragraph (z)(1)(i) of this section, calculate CO 2 4 2 4 4 (2) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(2)(i) of this section, then calculate emissions according to paragraph (z)(2)(ii) of this section. (i) The fuel combusted in the stationary or portable equipment is natural gas that is not pipeline quality or it is a blend containing natural gas that is not pipeline quality with only fuels that are listed in table C-1. The natural gas must meet the criteria of paragraphs (z)(2)(i)(A) through (C) of this section. (A) The natural gas must have a minimum higher heating value of 950 Btu per standard cubic foot. (B) The natural gas must have a maximum higher heating value of 1,100 Btu per standard cubic foot. (C) The natural gas must have a minimum CH 4 (ii) For fuels listed in paragraph (z)(2)(i) of this section, calculate CO 2 4 2 4 4 (3) If a fuel combusted in the stationary or portable equipment meets the specifications of paragraph (z)(3)(i) of this section, then calculate emissions according to paragraph (z)(3)(ii) of this section. (i) The fuel combusted in the stationary or portable equipment does not meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of this section. Examples include natural gas that is not of pipeline quality, natural gas that has a higher heating value of less than 950 Btu per standard cubic feet, and natural gas that is not pipeline quality and does not meet the criteria of either paragraph (z)(2)(i)(B) or (C) of this section. Other examples include field gas that does not meet the definition of natural gas in § 98.238 and blends containing field gas that does not meet the definition of natural gas in § 98.238. (ii) For fuels listed in paragraph (z)(3)(i) of this section, calculate combustion emissions for each unit or group of units combusting the same fuel using the applicable steps from paragraphs (z)(3)(ii)(A) through (G) of this section: (A) You may use company records to determine the volume of fuel combusted in the unit or group of units during the reporting year. (B) If you have a continuous gas composition analyzer on fuel to the combustion unit(s), you must use these compositions for determining the concentration of each constituent in the flow of gas to the unit or group of units. If you do not have a continuous gas composition analyzer on gas to the combustion unit(s), you may use engineering estimates based on best available data to determine the concentration of each constituent in the flow of gas to the unit or group of units. Otherwise, you must use the appropriate gas compositions for each stream going to the combustion unit(s) as specified in paragraph (u)(2) of this section. (C) For reciprocating internal combustion engines or gas turbines, you may conduct a performance test following the applicable procedures in § 98.234(i) and calculate CH 4 4 (D) Calculate GHG volumetric emissions at actual conditions using equations W-39A and W-39B to this section: Where: E a,CO 2 2 V a Y CO 2 2 η = Fraction of gas combusted for portable and stationary equipment determined using engineering estimation. For internal combustion devices that are not reciprocating internal combustion engines or gas turbines, a default of 0.995 can be used. For two-stroke lean-burn reciprocating internal combustion engines, a default of 0.953 must be used; for four-stroke lean-burn reciprocating internal combustion engines, a default of 0.962 must be used; for four-stroke rich-burn reciprocating internal combustion engines, a default of 0.997 must be used, and for gas turbines, a default of 0.999 must be used. Y j R j E a,CH 4 4 Y CH4 (E) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (F) Calculate both combustion-related CH 4 2 4 2 (G) Calculate CH 4 2 Where: Mass i 2 4 Fuel = Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV). HHV = Site-specific higher heating value of the fuel, mmBtu/unit of the fuel (in units consistent with the fuel quantity combusted). EF i 2 −4 2 4 4 4 1 × 10 −3 (4) For each natural gas-fired reciprocating internal combustion engine or gas turbine calculating emissions according to paragraph (z)(1)(ii) or (z)(2)(ii) of this section, you must determine a CH 4 4 4 4 4 (i) Conduct a performance test following the applicable procedures in § 98.234(i). If you are required or elect to conduct a performance test for any reason, you must use that result to determine the CH 4 4 (ii) Original equipment manufacturer information, which may include manufacturer specification sheets, emissions certification data, or other manufacturer data providing expected emission rates from the reciprocating internal combustion engine or gas turbine. (iii) Applicable equipment type-specific emission factor from table W-7 to this subpart. (5) Emissions from fuel combusted in stationary or portable equipment at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities that are calculated according to the procedures in either paragraph (z)(1)(ii) or (z)(2)(ii) of this section must be reported according to the requirements specified in § 98.236(z) rather than the reporting requirements specified in subpart C of this part. (6) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each external fuel combustion unit. (7) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit. (aa) through (cc) [Reserved] (dd) Drilling mud degassing. 4 (1) Calculation Method 1. 4 4 4 (i) Calculate CH 4 4 Where: E s,CH4,r 4 MR r T r X n GHG CH4 4 0.1337 = Conversion from gallons to standard cubic feet. (ii) Calculate the emissions rate of CH 4 Where: ER s,CH4,r 4 E s,CH4,r 4 T r (iii) Use equation W-43 to this section to calculate emissions for any wells drilled in the same sub-basin and within the equivalent stratigraphic interval in the reporting year. Where: E s,CH4,p 4 ER s,CH4,r 4 T p (iv) Calculate CH 4 (2) Calculation Method 2. Where: Mass CH4,p 4 EF CH4 4 DD p X CH4 4 83.85 = The mole percent of methane from the vented gas used to derive the emission factor (EF). (3) Calculation Method 3 4 CH4,p s,CH4,p s,CH4,p (ee) Crankcase venting. 4 4 4 2 2 (1) Calculation Method 1. 4 (i) Determine the volumetric flow from the crankcase vent at standard conditions using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. Each measurement must be conducted within 10 percent of 100 percent peak load. You may not measure during period of startup, shutdown, or malfunction. (ii) You may choose to use any of the methods set forth in § 98.234(a)(1) through (3) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a)(1) through (3), then you must use one of the methods specified in paragraphs (ee)(1)(i) of this section to determine the volumetric flow from the crank case vent at standard conditions. If emissions are not detected using the methods in § 98.234(a)(1) through (3), then you may assume that the emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a)(1) through (3), emissions are detected whenever a leak is detected according to the method. (iii) If conducting measurements for a manifolded group of crankcase vent sources, you must measure at a single point in the manifold downstream of all crankcase vent inputs and, if practical, prior to comingling with other non-compressor emission sources. Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (ee)(1)(i) of this section. If the manifolded group contains only crankcase vent sources, divide the measured volumetric flow equally between all operating reciprocating internal combustion engines. If the manifolded group contains crankcase vent sources and compressor vent sources, follow the methods for manifolded sources provided in paragraphs (o) or (p) of this section, as applicable, and report emissions from the crankcase vent as specified in § 98.236(o) or (p), as applicable. (iv) Using equation W-45 to this section, calculate the annual volumetric CH 4 Where: E CH4 4 MT s,CCV GHG CH4 4 4 4 T = Total operating hours per year for the reciprocating internal combustion engine. (v) You must calculate CH 4 (2) Calculation Method 2. Calculate annual CH 4 Where: E CH4 4 EF = Emission factor for crankcase venting on the reciprocating internal combustion engine, in kilograms CH 4 4 4 0.001 = Conversion from kilograms to metric tons. T = Total operating hours per year for the reciprocating internal combustion engine. [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80575, Dec. 23, 2011; 77 FR 51490, Aug. 24, 2012; 78 FR 71960, Nov. 29, 2013; 79 FR 70408, Nov. 25, 2014; 80 FR 64284, Oct. 22, 2015; 81 FR 86511, Nov. 30, 2016; 89 FR 42223, 42237, May 14, 2024; 89 FR 71842, 71847, Sept. 4, 2024] § 98.234 Monitoring and QA/QC requirements. The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR part 550. (a) You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of through-valve leakage from all source types listed in § 98.233(k), (o), and (p) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(i) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(ii) that occur during a calendar year. You must use one of the methods described in paragraph (a)(6) or (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(iii). If electing to comply with § 98.233(q) as specified in § 98.233(q)(1)(iv), you must use any of the methods described in paragraphs (a)(1) through (7) of this section to conduct leak detection(s) of equipment leaks from component types as specified in § 98.233(q)(1)(iv) that occur during a calendar year. (1) Optical gas imaging instrument. (i) Optical gas imaging instrument as specified in § 60.18 of this chapter. Alternative work practice for monitoring equipment leaks Detection Sensitivity Levels; (ii) Optical gas imaging instrument as specified in § 60.5397a of this chapter. (A) For the purposes of this subpart, any visible emissions observed by the optical gas imaging instrument from a component required or elected to be monitored as specified in § 98.233(q)(1) is a leak. (B) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.” (C) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).” (iii) Optical gas imaging instrument as specified in appendix K to part 60 of this chapter Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging. (2) Method 21. (i) Method 21 with a leak definition of 10,000 ppm. (ii) Method 21 with a leak definition of 500 ppm. (3) Infrared laser beam illuminated instrument. (4) [Reserved] (5) Acoustic leak detection device. (b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in § 98.233 according to the procedures in § 98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (c) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures and below the maximum temperature specified by the vent bag manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission can be tightly encompassed for measurement till the bag is completely filled. (1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation time. (2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings. (3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). (4) Estimate CH 4 2 (d) Use a high volume sampler to measure emissions within the capacity of the instrument. (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methods relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source. (2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti-static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer's manual. (3) For high volume samplers that output methane mass emissions, you must use the calculations in § 98.233(u) and (v) in reverse to determine the natural gas volumetric emissions at standard conditions. For high volume samplers that output methane volumetric flow in actual conditions, divide the volumetric methane flow rate by the mole fraction of methane in the natural gas according to the provisions in § 98.233(u) and estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH 4 2 (4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH 4 (5) If the measured methane flow exceeds the manufacturer's reported quantitation limit or if the measured natural gas flow determined as specified in paragraph (d)(3) of this section exceeds 70 percent of the manufacturer's reported maximum sampling flow rate, then the flow exceeds the capacity of the instrument and you must either use a temporary or permanent flow meter according to paragraph (b) of this section or use calibrated bags according to paragraph (c) of this section to determine the leak or flow rate. If you elect to use OGI to demonstrate that 100 percent of the flow is captured by the high volume sampler throughout the measurement period, then the measured flow rate above the 70 percent maximum sampling rate provision can be used. However, if any emissions are observed via OGI escaping capture of the high volume sampler during a measurement period, then that measurement is considered invalid ( i.e., (e) Peng Robinson Equation of State means the equation of state defined by equation W-47 to this section: Where: p = Absolute pressure. R = Universal gas constant. T = Absolute temperature. V m Where: ω = Acentric factor of the species. T c P c (f) [Reserved] (g) [Reserved] (h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the term “T p p (i) You must use any of the applicable methods described in paragraphs (i)(1) through (4) of this section to conduct a performance test to determine the concentration of CH4 in the exhaust gas. This concentration must be used to develop a CH4 emission factor (kg/MMBtu) for estimating combustion slip from reciprocating internal combustion engines or gas turbines as specified in § 98.233(z)(4). You may not conduct performance tests during period of startup, shutdown or malfunction. You must conduct three separate test runs for each performance test. Each test run must be conducted within 10 percent of 100 percent peak (or the highest achievable) load and last at least 1 hour. (1) EPA Method 18 in appendix A-6 to part 60 of this chapter. (2) EPA Method 320 in appendix A to part 63 of this chapter. (3) ASTM D6348-12 (Reapproved 2020) (incorporated by reference, see § 98.7). (4) EPA Method 25A in appendix A-7 to part 60 of this chapter, with the use of nonmethane cutter as described in § 1065.265 of this chapter. [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 22827, Apr. 25, 2011; 76 FR 59540, Sept. 27, 2011; 76 FR 80586, Dec. 23, 2011; 78 FR 25395, May 1, 2013; 79 FR 70410, Nov. 25, 2014; 80 FR 64291, Oct. 22, 2015; 81 FR 86514, Nov. 30, 2016; 89 FR 42287, May 14, 2024] § 98.235 Procedures for estimating missing data. Except as specified in § 98.233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation or activity data are not collected), you must follow the procedures specified in paragraphs (a) through (i) of this section, as applicable. (a) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part. (b) For each missing value of a parameter that should have been measured quarterly or more frequently using equipment including, but not limited to, a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, you must use the first quality-assured value obtained after the missing data period as the substitute data value. A value is quality-assured according to the procedures specified in § 98.234. (c) For each missing value of a parameter that should have been measured annually, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year's emissions estimation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection. (d) For each missing value of a parameter that should have been measured biannually (every two years), you must conduct the estimation or measurement activity for those sources as soon as possible in the subsequent calendar year if the estimation or measurement was not made in the appropriate year (first year of data collection and every two years thereafter), until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used to alternate or postpone subsequent biannual emissions estimations or measurements. (e) For the first 6 months of required data collection, facilities that become newly subject to this subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart. (f) For the first 6 months of required data collection, facilities that are currently subject to this subpart W and that start up new emission sources or acquire new sources from another facility that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly operating or newly acquired sources that cannot reasonably be measured or obtained according to the requirements of this subpart. (g) Unless addressed in another paragraph of this section, for each missing value of any activity data, you must substitute data value(s) using the best available estimate(s) of the parameter(s), based on all applicable and available process or other data (including, but not limited to, processing rates, operating hours). (h) You must report information for all measured and substitute values of a parameter, and the procedures used to substitute an unavailable value of a parameter per the requirements in § 98.236(bb). (i) You must follow recordkeeping requirements listed in § 98.237(f). [79 FR 70410, Nov. 25, 2014, as amended at 89 FR 42289, May 14, 2024] § 98.236 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather than the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure. (a) The annual report must include the information specified in paragraphs (a)(1) through (10) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (10) of this section, and each applicable emission source listed in paragraphs (b) through (z), (dd) and (ee) of this section. (1) Onshore petroleum and natural gas production. (i) Natural gas pneumatic devices. (ii) Natural gas driven pneumatic pumps. (iii) Acid gas removal units and nitrogen removal units. (iv) Dehydrators. (v) Liquids unloading. (vi) Completions and workovers with hydraulic fracturing. (vii) Completions and workovers without hydraulic fracturing. (viii) Blowdown vent stacks. (ix) Hydrocarbon liquids and produced water storage tanks. (x) Well testing. (xi) Associated natural gas. (xii) Flare stacks. (xiii) Centrifugal compressors. (xiv) Reciprocating compressors. (xv) Equipment leak surveys. (xvi) Equipment leaks by population count. (xvii) EOR injection pumps. (xviii) EOR hydrocarbon liquids. (xix) Other large release events. (xx) Combustion equipment. (xxi) Drilling mud degassing. (xxii) Crankcase vents. (2) Offshore petroleum and natural gas production. (i) Offshore petroleum and natural gas production. (ii) Other large release events. (3) Onshore natural gas processing. (i) Natural gas pneumatic devices. (ii) Acid gas removal units and nitrogen removal units. (iii) Dehydrators. (iv) Blowdown vent stacks. (v) Hydrocarbon liquids and produced water storage tanks. (vi) Flare stacks. (vii) Centrifugal compressors. (viii) Reciprocating compressors. (ix) Equipment leak surveys. (x) Other large release events. (xi) Crankcase vents. (4) Onshore natural gas transmission compression. (i) Natural gas pneumatic devices. (ii) Dehydrators. (iii) Blowdown vent stacks. (iv) Condensate storage tanks. (v) Flare stacks. (vi) Centrifugal compressors. (vii) Reciprocating compressors. (viii) Equipment leak surveys. (ix) Other large release events. (x) Crankcase vents. (5) Underground natural gas storage. (i) Natural gas pneumatic devices. (ii) Dehydrators. (iii) Blowdown vent stacks. (iv) Condensate storage tanks. (v) Flare stacks. (vi) Centrifugal compressors. (vii) Reciprocating compressors. (viii) Equipment leak surveys. (ix) Equipment leaks by population count. (x) Other large release events. (xi) Crankcase vents. (6) LNG storage. (i) Acid gas removal units and nitrogen removal units. (ii) Blowdown vent stacks. (iii) Flare stacks. (iv) Centrifugal compressors. (v) Reciprocating compressors. (vi) Equipment leak surveys. (vii) Equipment leaks by population count. (viii) Other large release events. (ix) Crankcase vents. (7) LNG import and export equipment. (i) Acid gas removal units and nitrogen removal units. (ii) Blowdown vent stacks. (iii) Flare stacks. (iv) Centrifugal compressors. (v) Reciprocating compressors. (vi) Equipment leak surveys. (vii) Equipment leaks by population count. (viii) Other large release events. (ix) Crankcase vents. (8) Natural gas distribution. (i) Natural gas pneumatic devices. (ii) Blowdown vent stacks. (iii) Equipment leak surveys. (iv) Equipment leaks by population count. (v) Other large release events. (vi) Combustion equipment. (vii) Crankcase vents. (9) Onshore petroleum and natural gas gathering and boosting. (i) Natural gas pneumatic devices. (ii) Natural gas driven pneumatic pumps. (iii) Acid gas removal units and nitrogen removal units. (iv) Dehydrators. (v) Blowdown vent stacks. (vi) Hydrocarbon liquids and produced water storage tanks. (vii) Flare stacks. (viii) Centrifugal compressors. (ix) Reciprocating compressors. (x) Equipment leak surveys. (xi) Equipment leaks by population count. (xii) Other large release events. (xiii) Combustion equipment. (xiv) Crankcase vents. (10) Onshore natural gas transmission pipeline. (i) Blowdown vent stacks. (ii) Equipment leaks by population count. (iii) Other large release events. (b) Natural gas pneumatic devices. (1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (2) The number of natural gas pneumatic devices as specified in paragraphs (b)(2)(i) through (viii) of this section, as applicable. If a natural gas pneumatic device was vented directly to the atmosphere for part of the year and routed to a flare, combustion unit, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (b)(2)(ii) through (vii) of this section. (i) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed), determined according to § 98.233(a)(5) through (7). (ii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere, determined according to § 98.233(a)(5) through (7). (iii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) routed to a flare, combustion, or vapor recovery system. (iv) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1). (v) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2). (vi) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3). (vii) The total number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4). (viii) If the reported values in paragraphs (b)(2)(i) through (vii) of this section are estimated values determined according to § 98.233(a)(6), then you must report the information specified in paragraphs (b)(2)(viii)(A) through (C) of this section. (A) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are counted. (B) The number of natural gas pneumatic devices of each type reported in paragraphs (b)(2)(i) through (vii) of this section that are estimated (not counted). (C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting. (3) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 1 according to § 98.233(a)(1), report the information in paragraphs (b)(3)(i) through (vi) of this section for each measurement location. (i) Unique measurement location identification number. (ii) Type of flow monitor (volumetric flow monitor; mass flow monitor). (iii) Number of natural gas pneumatic devices of each type (continuous low bleed, continuous high bleed, and intermittent bleed) downstream of the flow monitor. (iv) An indication of whether a natural gas driven pneumatic pump is also downstream of the flow monitor. (v) Annual CO 2 2 (vi) Annual CH 4 4 (4) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 2 according to § 98.233(a)(2), report the information in paragraphs (b)(4)(i) through (ii) of this section, as applicable. (i) For onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting facilities: (A) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler). (B) The average number of hours each type of the natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed) was in service ( i.e., (C) Annual CO 2 2 (D) Annual CH 4 4 (ii) For onshore natural gas processing facilities, onshore natural gas transmission compression facilities, underground natural gas storage facilities, and natural gas distribution facilities: (A) The number of years used in the current measurement cycle. (B) Indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler) to measure the emissions from natural gas pneumatic devices at this facility. (C) Indicate whether the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233. (D) If the emissions from any natural gas pneumatic devices at this facility were calculated using equation W-1B to § 98.233, report the following information for each type of natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed). ( 1 ( 2 i.e., y n Count t,y ( 3 i.e., t ( 4 i.e., t (E) Annual CO 2 2 (F) Annual CH 4 4 (G) Annual CO 2 2 (H) Annual CH 4 4 (5) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 3 according to § 98.233(a)(3), report the information in paragraphs (b)(5)(i) through (iv) of this section. (i) For continuous high bleed and continuous low bleed natural gas pneumatic devices: (A) Indicate whether you measured emissions according to § 98.233(a)(3)(i)(A) or used default emission factors according to § 98.233(a)(3)(i)(B) to calculate emissions from your continuous high bleed and continuous low bleed natural gas pneumatic devices vented directly to the atmosphere at this well-pad site, gathering and boosting site, or facility, as applicable. (B) If measurements were made according to § 98.233(a)(3)(i)(A), indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler). (C) If default emission factors were used according to § 98.233(a)(3)(i)(B) to calculate emissions, report the following information for each type of applicable natural gas pneumatic device (continuous low bleed and continuous high bleed). (1) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) or (a)(2)(iii) (“Count t (2) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service ( i.e., t (ii) For intermittent bleed natural gas pneumatic devices: (A) Indicate the primary monitoring method used (OGI; Method 21 at 10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the number of complete monitoring surveys conducted at the well-pad site or gathering and boosting site. (B) The total number of intermittent bleed natural gas pneumatic devices detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“x” in equation W-1C to § 98.233). (C) Average time the intermittent bleed natural gas pneumatic devices were in service ( i.e., mal,z (D) The total number of intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year (“Count” in equation W-1C to § 98.233). (E) Average time the intermittent bleed natural gas pneumatic devices that were monitored but were not detected as malfunctioning in any pneumatic device monitoring survey during the calendar year were in service ( i.e., avg (iii) Annual CO 2 2 (iv) Annual CH 4 4 (6) For natural gas pneumatic devices vented directly to the atmosphere for which emissions were calculated using Calculation Method 4 according to § 98.233(a)(4), report the following information for each type of applicable natural gas pneumatic device (continuous low bleed, continuous high bleed, and intermittent bleed). (i) Total number of natural gas pneumatic devices that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(a)(1) ( i.e., t (ii) The average estimated number of hours in the operating year that the natural gas pneumatic devices were in service ( i.e., t (iii) Annual CO 2 2 (iv) Annual CH 4 4 (c) Natural gas driven pneumatic pumps. (1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (2) The number of natural gas driven pneumatic pumps as specified in paragraphs (c)(2)(i) through (iv) of this section, as applicable. If a natural gas driven pneumatic pump was vented directly to the atmosphere for part of the year and routed to a flare, combustion, or vapor recovery system during another part of the year, then include the device in each of the applicable counts specified in paragraphs (c)(2)(ii) through (iv) of this section. (i) The total number of natural gas driven pneumatic pumps. (ii) The total number of natural gas driven pneumatic pumps vented directly to the atmosphere at any point during the year (including pumps that normally routed emissions to a flare but flow bypassed the flare for part of the year). (iii) The total number of natural gas driven pneumatic pumps routed to a flare at any point during the year. (iv) The total number of natural gas driven pneumatic pumps routed to combustion or a vapor recovery system at any point during the year. (3) For natural gas driven pneumatic pumps for which vented emissions were calculated using Calculation Method 1 according to § 98.233(c)(1), report the information in paragraphs (c)(3)(i) through (vi) of this section for each measurement location. (i) Unique measurement location identification number. (ii) Type of flow monitor (volumetric flow monitor; mass flow monitor). (iii) Number of natural gas driven pneumatic pumps downstream of the flow monitor. (iv) An indication of whether any natural gas pneumatic devices are also downstream of the monitoring location. (v) Annual CO 2 2 (vi) Annual CH 4 4 (4) If you used Calculation Method 2 according to § 98.233(c)(2) to calculate vented emissions, report the information in paragraphs (c)(4)(i) through (ix) of this section, as applicable. (i) The number of years used in the current measurement cycle. (ii) The total number of natural gas driven pneumatic pumps for which emissions were measured or calculated using Calculation Method 2. (iii) Indicate whether the emissions from the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year or if the emissions were calculated using equation W-2B to § 98.233. (iv) If the natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were measured during the reporting year, indicate the primary measurement method used (temporary flow meter, calibrated bagging, or high volume sampler). (v) If the emissions from natural gas driven pneumatic pumps at this well-pad site or gathering and boosting site, as applicable, were calculated using equation W-2B to § 98.233, report the following information: (A) The value of the emission factor for the reporting year as calculated using equation W-2A to § 98.233 (in scf/hour/pump). (B) The total number of natural gas driven pneumatic pumps measured across all years upon which the emission factor is based ( i.e. S y n Count y (C) Total number of natural gas driven pneumatic pumps that vent directly to the atmosphere and that were not directly measured according to the requirements in § 98.233(c)(1) or (c)(2)(iii) ( i.e. (D) The average estimated number of hours in the operating year the pumps were pumping liquid ( i.e. (vi) Annual CO 2 2 (vii) Annual CH 4 4 (viii) Annual CO 2 2 (ix) Annual CH 4 4 (5) If you used Calculation Method 3 according to § 98.233(c)(3) to calculate vented emissions, report the information in paragraphs (c)(5)(i) through (iv) of this section for the natural gas driven pneumatic pumps subject to Calculation Method 3. (i) Number of pumps that vent directly to the atmosphere ( i.e. (ii) Average estimated number of hours in the calendar year that natural gas driven pneumatic pumps that vented directly to atmosphere were pumping liquid (“T” in equation W-2B to § 98.233). (iii) Annual CO 2 2 (iv) Annual CH 4 4 (d) Acid gas removal units and nitrogen removal units. (1) You must report the information specified in paragraphs (d)(1)(i) through (xi) of this section for each acid gas removal unit or nitrogen removal unit, as applicable. (i) A unique name or ID number for the acid gas removal unit or nitrogen removal unit. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single acid gas removal unit or nitrogen removal unit for each location it operates at in a given year. (ii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a flare. If so, report the information specified in paragraphs (d)(1)(ii)(A) through (D) of this section for acid gas removal units and the information specified in paragraph (d)(1)(ii)(B) of this section for nitrogen removal units. (A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(d) as specified in § 98.233(n)(3)(ii)(B). (B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the acid gas removal unit or nitrogen removal unit vent was routed. (D) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the acid gas removal unit or nitrogen removal unit vent. (iii) Whether the acid gas removal unit or nitrogen removal unit vent was routed to combustion, and if so, whether it was routed for the entire year or only part of the year. (iv) Whether the acid gas removal unit or nitrogen removal unit vent was routed to a vapor recovery system, and if so, whether it was routed for the entire year or only part of the year. (v) Total feed rate entering the acid gas removal unit or nitrogen removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year. (vi) If the acid gas removal unit or nitrogen removal unit was routed to a flare, to combustion, or to vapor recovery for only part of the year, the feed rate entering the acid gas removal unit or nitrogen removal unit during the portion of the year that the emissions were vented directly to the atmosphere, using a meter or engineering estimate based on process knowledge or best available data, in million standard cubic feet per year. (vii) The calculation method used to calculate CO 2 4 4 (viii) Annual CO 2 2 (ix) Annual CH 4 4 (x) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit or nitrogen removal unit. (i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO 2 4 (A) Annual average volumetric fraction of CO 2 (B) Annual average volumetric fraction of CH 4 (C) Annual volume of gas vented from the acid gas removal unit or nitrogen removal unit, in cubic feet. (D) The temperature that corresponds to the reported annual volume of gas vented from the unit, in degrees Fahrenheit. If the annual volume of gas vented is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F. (E) The pressure that corresponds to the reported annual volume of gas vented from the unit, in pounds per square inch absolute. If the annual volume of gas vented is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia. (ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO 2 4 (A) Indicate which equation was used (equation W-4A, W-4B, or W-4C to § 98.233). (B) Annual average volumetric fraction of CO 2 (C) Annual average volumetric fraction of CO 2 (D) Annual average volumetric fraction of CO 2 (E) Annual average volumetric fraction of CH 4 (F) Annual average volumetric fraction of CH 4 (G) Annual average volumetric fraction of CH 4 (H) The total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in cubic feet at actual conditions. (I) The temperature that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F. (J) The pressure that corresponds to the reported total annual volume of natural gas flow into the acid gas removal unit or nitrogen removal unit, as specified in equation W-4A or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia. (K) The total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in cubic feet at actual conditions. (L) The temperature that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in degrees Fahrenheit. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual temperature; if it is reported in standard cubic feet, report 60 °F. (M) The pressure that corresponds to the reported total annual volume of natural gas flow out of the acid gas removal unit or nitrogen removal unit, as specified in equation W-4B or equation W-4C to § 98.233, in pounds per square inch absolute. If the total annual volume of natural gas flow is reported in actual cubic feet, report the actual pressure; if it is reported in standard cubic feet, report 14.7 psia. (iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO 2 4 (A) The name of the simulation software package used. (B) Annual average natural gas feed temperature, in degrees Fahrenheit. (C) Annual average natural gas feed pressure, in pounds per square inch. (D) Annual average natural gas feed flow rate, in standard cubic feet per minute. (E) Annual average acid gas content of the feed natural gas, in mole percent. (F) Annual average acid gas content of the outlet natural gas, in mole percent. (G) Annual average methane content of the feed natural gas, in mole percent. (H) Annual average methane content of the outlet natural gas, in mole percent. (I) Total annual unit operating hours, excluding downtime for maintenance or standby, in hours per year. (J) Annual average exit temperature of the natural gas, in degrees Fahrenheit. (K) Annual average solvent pressure, in pounds per square inch. (L) Annual average solvent temperature, in degrees Fahrenheit. (M) Annual average solvent circulation rate, in gallons per minute. (N) Solvent type used for the majority of the year, from one of the following options: Selexol TM TM SM TM (O) If a vent meter is installed and you elected to use Calculation Method 4 for an AGR, report the information in paragraphs (d)(2)(iii)(O)( 1 3 ( 1 a,meter ( 2 a,sim ( 3 (e) Dehydrators. (1) For each glycol dehydrator for which you calculated emissions using Calculation Method 1 (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator. If reported emissions are based on more than one simulation, you must report the average of the simulation inputs. (i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single dehydrator for each location it operates at in a given year. (ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day. (iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. (iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet. (v) Dehydrator absorbent circulation pump type ( e.g. (vi) Dehydrator absorbent circulation rate, in gallons per minute. (vii) Type of absorbent ( e.g. (viii) Whether stripping gas is used in dehydrator. (ix) Whether a flash tank separator is used in dehydrator. (x) Total time the dehydrator is operating during the year, in hours. (xi) Temperature of the wet natural gas at the absorber inlet, in degrees Fahrenheit. (xii) Pressure of the wet natural gas at the absorber inlet, in pounds per square inch gauge. (xiii) Mole fraction of CH 4 (xiv) Mole fraction of CO 2 (xv) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (xvi) If a flash tank separator is used in the dehydrator, then you must report the information specified in paragraphs (e)(1)(xvi)(A) through (F) of this section for the emissions from the flash tank vent, as applicable. If flash tank emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvi)(G) through (I) of this section for the combusted emissions from the flash tank vent. (A) Whether any flash gas emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination. (B) Annual CO 2 2 (C) Annual CH 4 4 (D) Annual CO 2 2 (E) Annual CH 4 4 (F) Annual N 2 2 (G) Indicate whether the regenerator firebox/fire tubes was monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvi)(E) and (F) and (e)(1)(xvi)(H) and (I) of this section do not apply. (H) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet. (I) Average combustion efficiency, expressed as a fraction of gas from the flash tank combusted by a burning regenerator firebox/fire tubes. (xvii) Report the information specified in paragraphs (e)(1)(xvii)(A) through (F) of this section for the emissions from the still vent, as applicable. If still vent emissions were routed to a regenerator firebox/fire tubes, then you must also report the information specified in paragraphs (e)(1)(xvii)(G) through (I) of this section for the combusted emissions from the still vent. (A) Whether any still vent emissions are vented directly to the atmosphere, routed to a flare, routed to the regenerator firebox/fire tubes, routed to a vapor recovery system, used as stripping gas, or any combination. (B) Annual CO 2 2 (C) Annual CH 4 4 (D) Annual CO 2 2 (E) Annual CH 4 4 (F) Annual N 2 2 (G) Indicate whether the regenerator firebox/fire tubes were monitored with a CEMS. If a CEMS was used, then paragraphs (e)(1)(xvii)(E) and (F) and (e)(1)(xvii)(H) and (I) of this section do not apply. (H) Total volume of gas from the still vent to a regenerator firebox/fire tubes, in standard cubic feet. (I) Average combustion efficiency, expressed as a fraction of gas from the still vent combusted by a burning regenerator firebox/fire tubes. (xviii) Name of the software package used. (2) You must report the information specified in paragraphs (e)(2)(i) through (vi) of this section for all glycol dehydrators with an annual average daily natural gas throughput greater than 0 million standard cubic feet per day and less than 0.4 million standard cubic feet per day for which you calculated emissions using Calculation Method 2 (as specified in § 98.233(e)(2)) at the facility, well-pad site, or gathering and boosting site. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) The total number of dehydrators at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 2. (iii) Whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system. (iv) Whether any dehydrator emissions were routed to a control device that reduces CO 2 4 2 4 (v) Whether any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(v)(A) through (E) of this section. (A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to regenerator firebox/fire tubes. (B) Total volume of gas from the flash tank to a regenerator firebox/fire tubes, in standard cubic feet. (C) Annual CO 2 2 (D) Annual CH 4 4 (E) Annual N 2 2 (vi) For dehydrator emissions that were not routed to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(vi)(A) and (B) of this section. (A) Annual CO 2 2 (B) Annual CH 4 4 (3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (viii) of this section for each well-pad site, gathering and boosting site, or facility, as applicable. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Count of desiccant dehydrators as specified in paragraphs (e)(3)(ii)(A) and (B) of this section that had one or more openings during the calendar year at the facility, well-pad site, or gathering and boosting site for which you calculated emissions using Calculation Method 3. (A) The number of opened desiccant dehydrators that used deliquescing desiccant ( e.g. (B) The number of opened desiccant dehydrators that used regenerative desiccant ( e.g. (iii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total physical volume of all opened dehydrator vessels. (iv) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, total number of dehydrator openings in the calendar year. (v) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a vapor recovery system. If any dehydrator emissions were routed to a vapor recovery system, then you must report the total number of dehydrators at the facility that routed to a vapor recovery system. (vi) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a control device that reduces CO 2 4 2 4 (vii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section, whether any dehydrator emissions were routed to a flare or a non-flare combustion unit. If any dehydrator emissions were routed to a flare or a non-flare combustion unit, then you must report the information specified in paragraphs (e)(3)(vii)(A) through (E) of this section. (A) The total number of dehydrators routed to a flare and the total number of dehydrators routed to a non-flare combustion unit. (B) Total volume of gas routed to non-flare combustion units, in standard cubic feet. (C) Annual CO 2 2 (D) Annual CH 4 4 (E) Annual N 2 2 (viii) For desiccant dehydrators at the facility, well-pad site, or gathering and boosting site identified in paragraph (e)(3)(ii) of this section that were not routed to a flare or a non-flare combustion unit, report the information specified in paragraphs (e)(3)(viii)(A) and (B) of this section. (A) Annual CO 2 2 (B) Annual CH 4 4 (4) For dehydrators that were routed to flares, report the information specified in paragraphs (e)(4)(i) through (iv) of this section. (i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(e) as specified in § 98.233(n)(3)(ii)(B). (ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the dehydrator vent was routed. (iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the dehydrator. (f) Liquids unloading. (1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts by unloading type combination (with or without plunger lifts, automated or manual unloading). (i) Well ID number. (ii) Well tubing diameter and pressure group ID. (iii) Unloading type combination (with or without plunger lifts, automated or manual unloading). (iv) [Reserved] (v) Indicate whether the monitoring period used to determine the cumulative amount of time venting to the atmosphere was not the full calendar year. (vi) Cumulative amount of time the well was vented directly to the atmosphere (“T p (vii) Cumulative number of unloadings vented directly to the atmosphere for the well. (viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1). (ix) Annual CO 2 2 (x) Annual CH 4 4 (xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (F) of this section for each individual well not using a plunger lift that was tested during the year. (A) Well ID number of tested well. (B) Casing pressure, in pounds per square inch absolute. (C) Internal casing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (F) Unloading type (automated or manual). (xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (F) of this section for each individual well using a plunger lift that was tested during the year. (A) Well ID number. (B) The tubing pressure, in pounds per square inch absolute. (C) The internal tubing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (F) Unloading type (automated or manual). (2) For each well for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading vented to the atmosphere, you must report the information in paragraphs (f)(2)(i) through (xii) of this section. Report information separately for each calculation method and unloading type combination (with or without plunger lifts, automated or manual unloadings). (i) Well ID number. (ii) Calculation method. (iii) Unloading type combination (with or without plunger lifts, automated or manual unloadings). (iv) [Reserved] (v) Cumulative number of unloadings venting directly to the atmosphere for the well. (vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable. (vii) Annual CO 2 2 (viii) Annual CH 4 4 (ix) Average flow-line rate of gas (average of “SFR p (x) Cumulative amount of time that wells were left open to the atmosphere during unloading events (sum of “HR p,q (xi) For each well without plunger lifts, the information in paragraphs (f)(2)(xi)(A) through (C) of this section. (A) Internal casing diameter (“CD p (B) Well depth (“WD p (C) Shut-in pressure, surface pressure, or casing pressure (“SP p (xii) For each well with plunger lifts, the information in paragraphs (f)(2)(xiii)(A) through (C) of this section. (A) Internal tubing diameter (“TD p (B) Tubing depth (“WD p (C) Flow line pressure (“SP p (g) Completions and workovers with hydraulic fracturing. (1) Well ID number. (2) Well type combination (horizontal or vertical, flared or vented, reduced emission completion or not a reduced emission completion, gas well or oil well). (3) Number of completions or workovers for each well. (4) Calculation method used. (5) If you used equation W-10A to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (v) of this section. (i) Cumulative gas flowback time, in hours, for all completions or workovers at the well from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T p,i p,s (ii) If the well is a measured well for the sub-basin and well-type combination, the flowback rate, in standard cubic feet per hour (average of “FR s,p (iii) If you used equation W-12C to § 98.233 to calculate the average gas production rate for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and (B) of this section. (A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR p (B) Volume of oil produced during the first 30 days of production after completion of the newly drilled well or well workover using hydraulic fracturing, in barrels (“V p (iv) Whether the flow rate during the initial flowback period was determined using: (A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator. (B) A multiphase flow meter upstream of the separator. (C) Equation W-11A or W-11B to § 98.233. (v) Whether the flow rate when sufficient quantities are present to enable separation was determined using: (A) A recording flow meter (digital or analog) installed on the vent line, downstream of a separator. (B) Equation W-11A or W-11B to § 98.233. (6) If you used equation W-10B to § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of this section. (i) Vented natural gas volume, in standard cubic feet (“FV s,p (ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour (“FR p,i (iii) If a multiphase flowmeter was used to measure the flow rate during the initial flowback period, report the average flow rate measured by the multiphase flow meter from the initiation of flowback to the beginning of the period of time when sufficient quantities of gas present to enable separation in standard cubic feet per hour. (7) Annual gas emissions, in standard cubic feet (“E s,n (8) Annual CO 2 2 (9) Annual CH 4 4 (10) Indicate whether natural gas emissions from completion(s) or workover(s) with hydraulic fracturing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (g)(10)(i) through (iv) of this section. (i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(g) as specified in § 98.233(n)(3)(ii)(B). (ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section. (iv) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section. (h) Completions and workovers without hydraulic fracturing. (1) For each well with one or more gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this section. (i) Well ID number. (ii) Number of well completions that vented gas directly to the atmosphere without flaring. (iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions without hydraulic fracturing (“T p (iv) Average daily gas production rate for all completions without hydraulic fracturing without flaring, in standard cubic feet per hour (“V p (v) Annual CO 2 2 s,p (vi) Annual CH 4 4 s,p (2) If your facility had well completions without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(2)(i) through (ii) and (viii) of this section, for each well. If your facility had well completions without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(2)(i) through (iv) and (viii) of this section, for each well. (i) Well ID number. (ii) Number of well completions that flared gas. (iii) Total number of hours that gas routed to a flare during venting for all completions without hydraulic fracturing (“T p (iv) Average daily gas production rate for all completions without hydraulic fracturing with flaring, in standard cubic feet per hour (“V p (v) [Reserved] (vi) [Reserved] (vii) [Reserved] (viii) Report the information specified in paragraphs (h)(2)(viii)(A) through (D). (A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B). (B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section. (D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section. (3) For each well with one or more gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section. (i) Well ID number. (ii) Number of workovers that vented gas to the atmosphere without flaring. (iii) Annual CO 2 2 s,wo (iv) Annual CH 4 4 s,wo (4) If your facility had well workovers without hydraulic fracturing and with flaring during the year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well. If your facility had well workovers without hydraulic fracturing during the year that routed to flares and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each well. (i) Well ID number. (ii) Number of workovers that flared gas. (iii)-(v) [Reserved] (vi) Report the information specified in paragraphs (h)(4)(vi)(A) through (D). (A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and (ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(h) as specified in § 98.233(n)(3)(ii)(B). (B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section. (D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section. (i) Blowdown vent stacks. (1) Report by equipment or event type. e.g. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Equipment or event type. For the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export equipment, or onshore petroleum and natural gas gathering and boosting industry segments, use the seven categories listed in § 98.233(i)(2)(iv)(A). For the natural gas distribution or onshore natural gas transmission pipeline industry segments, use the eight categories listed in § 98.233(i)(2)(iv)(B). (iii) Total number of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from equation W-14A or equation W-14B to § 98.233, for all unique physical volumes for the equipment or event type). (iv) Annual CO 2 2 (v) Annual CH 4 4 (2) Report by flow meter. e.g. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Annual CO 2 2 2 (iii) Annual CH 4 4 4 (3) Onshore natural gas transmission pipeline segment. (i) Annual CO 2 2 (ii) Annual CH 4 4 (iii) Annual number of blowdown events. (j) Hydrocarbon liquids and produced water storage tanks. (1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each well-pad site (for onshore petroleum and natural gas production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) and by calculation method and liquid type, as applicable. Onshore petroleum and natural gas gathering and boosting and onshore natural gas processing facilities do not report the information specified in paragraph (j)(1)(ix) of this section. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Calculation method used, and name of the software package used if using Calculation Method 1. (iii) The total annual hydrocarbon liquids or produced water volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable atmospheric pressure storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the well-pad site with hydrocarbon liquids or produced water production flowing to gas-liquid separators or direct to atmospheric pressure storage tanks for which you used the same calculation method. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total volume of hydrocarbon liquids or produced water from all wells and the well ID number(s) for the well(s) included in this volume. (iv) The average well, gas-liquid separator, or non-separator equipment temperature, in degrees Fahrenheit. (v) The average well, gas-liquid separator, or non-separator equipment pressure, in pounds per square inch gauge. (vi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, the average sales oil or stabilized hydrocarbon liquids API gravity, in degrees. (vii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CO 2 2 (viii) If you used Calculation Method 1 of § 98.233(j) to calculate GHG emissions for atmospheric pressure storage tanks receiving hydrocarbon liquids, the flow-weighted average concentration (mole fraction) of CH 4 4 (ix) The number of wells sending hydrocarbon liquids or produced water to gas-liquid separators or directly to atmospheric pressure storage tanks. (x) Count of atmospheric pressure storage tanks specified in paragraphs (j)(1)(x)(A) through (F) of this section. (A) The number of fixed roof atmospheric pressure storage tanks. (B) The number of floating roof atmospheric pressure storage tanks. (C) The number of atmospheric pressure storage tanks that vented gas directly to the atmosphere and did not control emissions using a vapor recovery system or one or more flares at any point during the reporting year. (D) The number of atmospheric pressure storage tanks that routed emissions to a vapor recovery system at any point during the reporting year. (E) The number of atmospheric pressure storage tanks that routed emissions to one or more flares at any point during the reporting year. (F) The number of atmospheric pressure storage tanks in paragraph (j)(1)(x)(D) or (E) of this section that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare. (xi) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO 2 2 (xii) Annual CH 4 4 (xiii) For the atmospheric pressure storage tanks receiving hydrocarbon liquids identified in paragraphs (j)(1)(x)(D) of this section, total CO 2 2 (xiv) For the atmospheric pressure storage tanks identified in paragraphs (j)(1)(x)(D) of this section, total CH 4 4 (xv) For the atmospheric pressure storage tanks identified in paragraph (j)(1)(x)(F) of this section, the total volume of gas vented through open thief hatches, in scf, during periods while the storage tanks were also routing emissions to vapor recovery systems and/or flares. (2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section. (i) Report the information specified in paragraphs (j)(2)(i)(A) through (H) of this section, at the facility level, for atmospheric pressure storage tanks where emissions were calculated using Calculation Method 3 of § 98.233(j). (A) The total annual hydrocarbon liquids throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells at the facility with hydrocarbon liquids production that send hydrocarbon liquids to atmospheric pressure storage tanks for which emissions were calculated using Calculation Method 3. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the total annual hydrocarbon liquids throughput from all wells and the well ID number(s) for the well(s) included in this volume. (B) The total annual produced water throughput that is sent to all atmospheric pressure storage tanks in the facility with emissions calculated using Calculation Method 3, in barrels, specified in paragraphs (j)(2)(i)(B)( 1 3 ( 1 ( 2 ( 3 (C) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares. (D) An estimate of the fraction of hydrocarbon liquids throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems. (E) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with flares. (F) An estimate of the fraction of total produced water throughput reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric pressure storage tanks in the facility that controlled emissions with vapor recovery systems. (G) The number of fixed roof atmospheric pressure storage tanks in the facility. (H) The number of floating roof atmospheric pressure storage tanks in the facility. (ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (H) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) with atmospheric pressure storage tanks receiving hydrocarbon liquids whose emissions were calculated using § 98.233(j)(3)(i). (A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3. (C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3. (D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare. (E) The total number of separators, wells, or non-separator equipment with annual average daily hydrocarbon liquids throughput greater than 0 barrels per day and less than 10 barrels per day for which you used Calculation Method 3 (“Count” from equation W-15A to § 98.233). (F) Annual CO 2 2 (G) Annual CH 4 4 (H) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares. (iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (F) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for onshore natural gas processing) with atmospheric pressure storage tanks receiving produced water whose emissions were calculated using § 98.233(j)(3)(ii). (A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (B) The number of atmospheric pressure storage tanks that did not control emissions with flares and for which emissions were calculated using Calculation Method 3. (C) The number of atmospheric pressure storage tanks that controlled emissions with flares and for which emissions were calculated using Calculation Method 3. (D) The number of atmospheric pressure storage tanks that had an open thief hatch at some point during the year while the storage tank was also routing emissions to a vapor recovery system and/or a flare. (E) Annual CH 4 4 (F) The total volume of gas vented through open thief hatches, in scf, during periods while the atmospheric pressure storage tanks were also routing emissions to vapor recovery systems and/or flares. (3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (v) of this section for each well-pad site (for onshore production), gathering and boosting site (for onshore petroleum and natural gas gathering and boosting), or facility (for all other applicable industry segments) by liquid type. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year. (iii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the “T dv (iv) For atmospheric pressure storage tanks receiving hydrocarbon liquids, annual CO 2 2 (v) Annual CH 4 4 (4) For atmospheric pressure storage tanks that were routed to flares, report the information specified in paragraphs (j)(4)(i) through (iv) of this section. (i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(j) as specified in § 98.233(n)(3)(ii)(B). (ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (iii) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section to which the atmospheric pressure storage tank vent was routed. (iv) The unique ID for the stream routed to the flare as specified in paragraph (n)(3) of this section from the atmospheric pressure storage tank. (k) Condensate storage tanks. You must indicate whether your facility contains any condensate storage tanks. If your facility contains at least one condensate storage tank, then you must report the information specified in paragraphs (k)(1) and (2) of this section for each condensate storage tank vent stack. (1) For each condensate storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section. (i) The unique name or ID number for the condensate storage tank vent stack. (ii) Indicate if a flare is attached to the condensate storage tank vent stack. (iii) Indicate whether scrubber dump valve leakage occurred for the condensate storage tank vent according to § 98.233(k)(1). (iv) Which method specified in § 98.233(k)(1) was used to determine if dump valve leakage occurred. (2) If scrubber dump valve leakage occurred for a condensate storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each condensate storage vent stack where scrubber dump valve leakage occurred. (i) Which method specified in § 98.233(k)(2) was used to measure the leak rate. (ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour. (iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used). (iv) Annual CO 2 2 (v) Annual CH 4 4 (l) Well testing. (1) For oil wells not routed to a flare, you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section for each well tested. (i) [Reserved] (ii) Well ID number. (iii) Number of well testing days for the tested well in the calendar year. (iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well. (v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well. (vi) Annual CO 2 2 (vii) Annual CH 4 4 (2) For oil wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(2)(i) through (ii) and (ix) of this section, for each well tested. For oil wells routed to a flare and where you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(2)(i) through (v) and (ix) of this section. All reported data elements should be specific to the well for which equation W-17A to § 98.233 was used and for which well testing emissions were routed to flares. (i) [Reserved] (ii) Well ID number. (iii) Number of well testing days for the tested well in the calendar year. (iv) Average gas to oil ratio for the tested well, in cubic feet of gas per barrel of oil. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the average gas to oil ratio for the tested well. (v) Average flow rate for the tested well, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average flow rate for the tested well. (vi)-(viii) [Reserved] (ix) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(2)(ix)(A) through (D). (A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B). (B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section. (D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section. (3) For gas wells not routed to a flare, you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section for each well tested. (i) [Reserved] (ii) Well ID number. (iii) Number of well testing days for the tested well in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well. (iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well. (v) Annual CO 2 2 (vi) Annual CH 4 4 (4) For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (l)(4)(i) through (ii) and (viii) of this section, for each well tested. For gas wells routed to a flare and where you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (l)(4)(i) through (iv) and (viii) of this section for each well tested. All reported data elements should be specific to the well for which equation W-17B to § 98.233 was used and for which well testing emissions were routed to flares. (i) [Reserved] (ii) Well ID number. (iii) Number of well testing days for the tested well in the calendar year. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the number of well testing days for the tested well. (iv) Average annual production rate for the tested well, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured average annual production rate for the tested well. (v)-(vii) [Reserved] (viii) Indicate whether natural gas emissions from well testing were routed to a flare and emissions are reported according to paragraph (n) of this section, and if so, provide the information specified in paragraphs (l)(4)(viii)(A) through (D). (A) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(l) as specified in § 98.233(n)(3)(ii)(B). (B) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (C) The unique name or ID for the flare stack as specified in paragraph (n)(1) of this section. (D) The unique ID for each stream routed to the flare as specified in paragraph (n)(3) of this section. (m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented during the calendar year, then you must report the information specified in paragraphs (m)(1) through (7) of this section for each well for which associated gas was vented. If associated gas was flared during the calendar year and you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), then you must report the information specified in paragraphs (m)(1) through (3) of this section, for each well. If associated gas was flared and you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) to determine natural gas volumes as specified in § 98.233(n)(3)(ii)(B), then you must report the information specified in paragraphs (m)(1) through (6) of this section for each well. (1) Well ID number. (2) Indicate whether any associated gas was vented directly to the atmosphere without flaring. (3) Indicate whether any associated gas was flared and emissions are reported according to paragraph (n) of this section, and, if so, provide the information specified in paragraphs (m)(3)(i) through (iv). (i) Indicate whether you calculated natural gas emissions routed to the flare using continuous parameter monitoring systems as specified in § 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition analyzers or sampling as specified in § 98.233(n)(4), or you calculated natural gas emissions routed to the flare using the calculation methods in § 98.233(m) as specified in § 98.233(n)(3)(ii)(B). (ii) Indicate whether natural gas emissions were routed to a flare for the entire year or only part of the year. (iii) The unique name or ID for the flare stack to which associated natural gas is routed as specified in paragraph (n)(1) of this section. (iv) The unique ID for each associated natural gas stream routed to the flare as specified in paragraph (n)(3) of this section. (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil during the reporting year. Do not report the GOR if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare ( i.e. (5) Volume of oil produced by the well, in barrels, in the calendar year only during the time periods in which associated gas was vented or flared (“V p i.e. (6) Total volume of associated gas sent to sales or used on site and not sent to a vent or flare, in standard cubic feet, in the calendar year only during time periods in which associated gas was vented or flared (“SG” value used in equation W-18 to § 98.233). You may delay reporting of this data element if you indicate in the annual report that the well is a wildcat well or delineation well. If you elect to delay reporting of this data element, you must report by the date specified in paragraph (cc) of this section the measured total volume of associated gas sent to sales for the well during the time periods in which associated gas venting and flaring was occurring. Do not report the volume of gas sent to sales if you vented or flared associated gas and used a continuous flow monitor to determine the total volume of associated gas vented or routed to the flare ( i.e. (7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (viii) of this section for each well. (i) [Reserved] (ii) Indicate whether the associated gas volume vented from the well was measured using a continuous flow monitor. (iii) Indicate whether associated gas streams vented from the well were measured with a continuous gas composition analyzer. (iv) Total volume of associated gas vented from the well, in standard cubic feet. (v) Flow-weighted average mole fraction of CH 4 (vi) Flow-weighted average mole fraction of CO 2 (vii) Annual CO 2 2 (viii) Annual CH 4 4 (n) Flare stacks. (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year. (2) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (3) Unique IDs for each stream routed to the flare and the source type that generated the stream, if you determine the flow of each stream that is routed to the flare as specified in § 98.233(n)(3)(ii) and/or you determine the gas composition for each stream routed to the flare as specified in § 98.233(n)(4)(iii). If you determine flow or composition for a combined stream from multiple source types, then report the source type that provides the most gas to the combined stream. For source types not listed in § 98.233(n)(3)(ii)(B)( 1 7 (4) Indicate the type of flare ( i.e. (5) Indicate the type of flare assist ( i.e. (6) Indicate whether the pilot flame or combustion flame was monitored continuously, visually inspected, or both. If visually inspected, report the number of inspections during the year. If the pilot flame was monitored continuously, report the number of times all continuous monitoring devices were out of service or otherwise inoperable for a period of more than one week. (7) Indicate whether you measured total flow at the inlet to the flare as specified in § 98.233(n)(3)(i) or whether you determined flow for individual streams routed to the flare as specified in § 98.233(n)(3)(ii). If you measured total flow, indicate whether the volume of gas was determined using a continuous flow measurement device or whether it was determined using parameter monitoring and engineering calculations. If you determined flow for individual streams, indicate for each stream whether flow was determined using a continuous flow measurement device, parameter monitoring and engineering calculations, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used. (8) Indicate whether a continuous gas composition analyzer was used at the inlet to the flare as specified in § 98.233(n)(4)(i), whether composition at the inlet to the flare was determined based on sampling and analysis as specified in § 98.233(n)(4)(ii), or if composition was determined for individual streams as specified in § 98.233(n)(4)(iii). If you determined composition for individual streams, indicate for each stream whether composition was determined using a continuous gas composition analyzer, sampling and analysis, or other simulation or engineering calculation methods. If you switched from one method to another during the year, then indicate multiple methods were used. (9) Indicate whether you directly measured annual average HHV of the inlet stream to the flare as specified in § 98.233(n)(8)(i), calculated the annual average HHV of the inlet stream to the flare based on composition of the inlet stream as specified in § 98.233(n)(8)(ii), directly measured the annual average HHV of individual streams routed to the flare as specified in § 98.233(n)(8)(iii), or calculated the annual average HHV of individual streams based on their composition as specified in § 98.233(n)(8)(iv). (10) Annual average HHV of the inlet stream to the flare determined as specified in § 98.233(n)(8)(i) or (ii); both the calculated flow-weighted annual average HHV of the inlet stream to the flare and each individual stream HHV determined as specified in § 98.233(n)(8)(iii)(B) or (iv)(B); or each individual stream HHV, if you determined HHVs for each individual stream routed to the flare and you used these HHVs to calculate N 2 (11) Volume of gas sent to the flare, in standard cubic feet (“V s s s (12) Fraction of the feed gas sent to an un-lit flare based on total time when continuous monitoring of the pilot or periodic inspections indicated the flare was not lit and measured or calculated flow during the times when the flare was not lit (“Z U (13) Flare destruction efficiency, expressed as the fraction of hydrocarbon compounds in gas that is destroyed by a burning flare, but may or may not be completely oxidized to CO 2 (i) If you use tier 1, report the following: (A) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(i). (B) [Reserved] (ii) If you use tier 2, report the following: (A) Indicate if you are subject to part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter or if you are electing to comply with the flare monitoring requirements in part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. (B) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, indicate whether you are electing to comply with § 98.233(n)(1)(ii)(A), (B), (C), or (D). (C) If you are not required to comply with part 60, subpart OOOOb of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and the flare is an enclosed ground level flare or an enclosed elevated flare, indicate if your most recent performance test was conducted using the method in § 60.5413b(b) of this chapter (as specified in § 98.233(n)(1)(ii)(A)), the method in § 60.5413b(d) of this chapter (as specified in § 98.233(n)(1)(ii)(C)), or if it was conducted using OTM-52. (D) Number of days in periods of 15 or more consecutive days when you did not conform with all cited provisions in § 98.233(n)(1)(ii). (iii) Indicate if you use an alternative test method approved under § 60.5412b(d) of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter. If you use an approved alternative test method, indicate the approved destruction efficiency for the method, the date when you started to use the method, and the name or ID of the method. (14) Annual average mole fraction of CH 4 CH4 4 (15) Except as specified in paragraph (n)(20) of this section, annual average mole fraction of CO 2 CO2 2 (16) Annual CO 2 2 (17) Annual CH 4 4 (18) Annual N 2 2 (19) Estimated disaggregated CH 4 2 2 i.e. (20) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used, then you are not required to report the CO 2 (o) Centrifugal compressors. (1) Compressor activity data. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Unique name or ID for the centrifugal compressor. (iii) Hours in operating-mode. (iv) Hours in standby-pressurized-mode. (v) Hours in not-operating-depressurized-mode. (vi) If you conducted volumetric emission measurements as specified in § 98.233(o)(1): (A) Indicate whether the compressor was measured in operating-mode. (B) Indicate whether the compressor was measured in standby-pressurized-mode. (C) Indicate whether the compressor was measured in not-operating-depressurized-mode. (vii) Indicate whether the compressor has blind flanges installed and associated dates. (viii) Indicate whether the compressor has wet or dry seals. (ix) If the compressor has wet seals, the number of wet seals. (x) If the compressor has dry seals, the number of dry seals. (xi) Power output of the compressor driver (hp). (2) Compressor source. (A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(ii) of this section. (B) Centrifugal compressor source (wet seal, dry seal, isolation valve, or blowdown valve). (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source. (ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section. (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system. (B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent. (C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)( 1 2 (1) Annual CO 2 2 (2) Annual CH 4 4 (E) If the leak or vent is routed to flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device. (3) As found measurement sample data. (i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section. (A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section. (B) Measurement date. (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken. (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-23 to § 98.233 was used to calculate emissions in equation W-22 to § 98.233, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section. (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF s,m (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities. (4) Continuous measurement data. (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet. (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii). (iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources. (5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Report the following activity data. (A) Total number of centrifugal compressors at the facility. (B) Number of centrifugal compressors that have wet seals. (C) Number of centrifugal compressors that have atmospheric wet seal oil degassing vents ( i.e. (iii) Annual CO 2 2 (iv) Annual CH 4 4 (p) Reciprocating compressors. (1) Compressor activity data. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Unique name or ID for the reciprocating compressor. (iii) Hours in operating-mode. (iv) Hours in standby-pressurized-mode. (v) Hours in not-operating-depressurized-mode. (vi) If you conducted volumetric emission measurements as specified in § 98.233(p)(1): (A) Indicate whether the compressor was measured in operating-mode. (B) Indicate whether the compressor was measured in standby-pressurized-mode. (C) Indicate whether the compressor was measured in not-operating-depressurized-mode. (vii) Indicate whether the compressor has blind flanges installed and associated dates. (viii) Power output of the compressor driver (hp). (2) Compressor source. (A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section. (B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing). (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source. (ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section. (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion, or vapor recovery system. (B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent. (C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were conducted on the leak or vent. (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)( 1 2 ( 1 2 2 ( 2 4 4 (E) If the leak or vent is routed to a flare, combustion, or vapor recovery system, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device. (3) As found measurement sample data. (i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section. (A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section. (B) Measurement date. (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken. (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W-28 to § 98.233 was used to calculate emissions in equation W-27 to § 98.233, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section. (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF s,m (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count m (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities. (4) Continuous measurement data. (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet. (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii). (iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources. (5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Report the following activity data. (A) Total number of reciprocating compressors at the facility. (B) Number of reciprocating compressors that have rod packing emissions vented directly to the atmosphere ( i.e. (iii) Annual CO 2 2 (iv) Annual CH 4 4 (q) Equipment leak surveys. (1) You must report the information specified in paragraphs (q)(1)(i) through (ix) of this section. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Except as specified in paragraph (q)(1)(iii) of this section, the number of complete equipment leak surveys performed during the calendar year. (iii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle. (iv) Except for natural gas distribution facilities and onshore natural gas transmission pipeline facilities, indicate whether any of the leak detection surveys used in calculating emissions per § 98.233(q)(2) were conducted for compliance with any of the standards in paragraphs (q)(1)(iv)(A) through (E) of this section. Report the indication per well-pad site, gathering and boosting site, or facility, not per component type, as applicable. (A) The well site or compressor station fugitive emissions standards in § 60.5397a of this chapter. (B) The well site, centralized production facility, or compressor station fugitive emissions standards in § 60.5397b or § 60.5398b of this chapter. (C) The well site, centralized production facility, or compressor station fugitive emissions standards in an applicable approved state plan or applicable Federal plan in part 62 of this chapter. (D) The standards for equipment leaks at onshore natural gas processing plants in § 60.5400b or § 60.5401b of this chapter. (E) The standards for equipment leaks at onshore natural gas processing plants in an applicable approved state plan or applicable Federal plan in part 62 of this chapter. (v) For facilities in onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment, indicate whether you elected to comply with § 98.233(q) according to § 98.233(q)(1)(iv) for any equipment components at your well-pad site, gathering and boosting site, or facility. (vi) Report each type of method described in § 98.234(a) that was used to conduct leak surveys. (vii) Report whether emissions were calculated using Calculation Method 1 (leaker factor emission calculation methodology) and/or using Calculation Method 2 (leaker measurement methodology). (viii) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) by service type for which leak detection surveys were conducted and emissions calculated according to § 98.233(q). (ix) For facilities in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting, report the number of major equipment (as listed in table W-1 to this subpart) in vacuum service as defined in § 98.238. (2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through (8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), (j)(10), (m)(3)(ii) or (m)(4)(ii) for your facility's industry segment. For each component type and leak detection method combination that is located at your well-pad site, gathering and boosting site, or facility, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section. If a component type is located at your well-pad site, gathering and boosting site, or facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (ix) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(vi) through (ix) of this section. If you used Calculation Method 1 (leaker factor emission calculation methodology) for some complete leak surveys and used Calculation Method 2 (leaker measurement methodology) for some complete leak surveys, you must report the information specified in paragraphs (q)(2)(i) through (ix) of this section separately for component surveys using Calculation Method 1 and Calculation Method 2. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Component type. (iii) Leak detection method used for the screening survey ( e.g. (iv) Emission factor or measurement method used ( e.g., (v) Total number of components surveyed by type and leak detection method in the calendar year. (vi) Total number of the surveyed component types by leak detection method that were identified as leaking in the calendar year (“xp” in equation W-30 to § 98.233 for the component type or the number of leaks measured for the specified component type according to the provisions in § 98.233(q)(3)). (vii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T p,z (viii) Annual CO 2 2 (ix) Annual CH 4 4 (3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section. (i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year. (ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (“Count MR,y (iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T w,y (iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle. (v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count MR,y (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T w,y (vii) Meter/regulator run CO 2 2 s,MR,i 2 (viii) Meter/regulator run CH 4 4 s,MR,i 4 (ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report: (A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility (“Count MR (B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg (C) Annual CO 2 2 (D) Annual CH 4 4 (r) Equipment leaks by population count. (1) You must indicate whether your facility contains any of the emission source types required to use equation W-32A to § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately for each emission source type required to use equation W-32A to § 98.233 that is located at your facility. For each well-pad site and gathering and boosting site at onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities, you must report the information specified in paragraphs (r)(1)(i) through (vi) of this section separately by equipment type and service type. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the equipment type and service type. (iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable (“Count e (iv) Average estimated time that the emission source type was operational in the calendar year, in hours (“T e (v) Annual CO 2 2 (vi) Annual CH 4 4 (2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section. (i) Number of above grade transmission-distribution transfer stations at the facility. (ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility. (iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count MR (iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T w,avg (v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report: (A) Annual CO 2 2 (B) Annual CH 4 4 (3) You must indicate whether your facility contains any emission source types in vacuum service as defined in § 98.238. If your facility contains equipment in vacuum service, you must report the information specified in paragraphs (r)(3)(i) through (iii) of this section separately for each emission source type in vacuum service that is located at your well-pad site, gathering and boosting site, or facility, as applicable. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Emission source type. (iii) Total number of the emission source type at the well-pad site, gathering and boosting site, or facility, as applicable. (s) Offshore petroleum and natural gas production. (1) The BOEM Facility ID(s) that correspond(s) to your facility, if applicable. (2) If you adjusted emissions according to § 98.233(s)(1)(ii) or (s)(2)(ii), report the information specified in paragraphs (s)(2)(i) and (ii) of this section. (i) Facility operating hours for the year of the most recent emissions calculated according to § 98.233(s)(1)(ii) or § 98.233(s)(2)(ii) prior to the current reporting year. (ii) Facility operating hours for the current reporting year. (3) For each emission source type listed in the most recent monitoring and calculation methods published by BOEM as referenced in 30 CFR 550.302 through 304, report the information specified in paragraphs (s)(3)(i) through (iii) of this section. (i) Annual CO 2 2 (ii) Annual CH 4 4 (iii) Annual N 2 2 (t)-(v) [Reserved] (w) EOR injection pumps. 2 (1) Sub-basin ID. (2) EOR injection pump system identifier. (3) Pump capacity, in barrels per day. (4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“Vv” in equation W-37 to § 98.233). (5) Number of blowdowns for the EOR injection pump system in the calendar year. (6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“Rc” in equation W-37 to § 98.233). (7) Mass fraction of CO 2 CO2 (8) Annual CO 2 2 (x) EOR hydrocarbon liquids. (1) Sub-basin ID. (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V hl (3) Average CO 2 hl (4) Annual CO 2 2 2 2 (y) Other large release events. (1) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (2) Unique release event identification number ( e.g. (3) The latitude and longitude of the release in decimal degrees to at least four digits to the right of the decimal point. (4) The approximate start date, start time, and duration (in hours) of the release event, and an indication of how the start date and time were determined (determined based on pressure monitor, temperature monitor, other monitored process parameter (specify), assigned based on last monitoring or measurement survey showing no large release (specify monitoring or measurement survey method), or used the 91-day default start date). (5) A general description of the event. Include: (i) Identification of the equipment involved in the release. (ii) A description of how the release occurred, from one of the following categories: maintenance event, fire/explosion, gas well blowout, oil well blowout, gas well release, oil well release, pressure relief, large leak, and other (specify). (iii) An indication of whether the release exceeded a threshold in § 98.233(y)(1)(i) or in § 98.233(y)(1)(ii). (iv) A description of the technology or method used to identify the release. (v) An indication of whether the release was identified under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter and, if the release was identified under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter, a unique notification ID number for the notification as assigned in paragraph (y)(11)(i) of this section. (vi) An indication of whether a portion of the natural gas released was combusted during the release, and if so, the fraction of the natural gas released that was estimated to be combusted and the assumed combustion efficiency for the combusted natural gas. (6) The total volume of gas released during the event in standard cubic feet. (7) The volume fraction of CO 2 (8) The volume fraction of CH 4 (9) Annual CO 2 2 (10) Annual CH 4 4 4 (11) Report the total number of super-emitter release notifications received from the EPA under the provisions of §§ 60.5371, 60.5371a, or 60.5371b of this chapter or an applicable approved state plan or applicable Federal plan in part 62 of this chapter for this facility for events that occurred during the reporting year that were not determined by the EPA to have a demonstratable error in the notification and, for each such super-emitter release notification, report the information specified in paragraphs (y)(11)(i) through (v) of this section. (i) Unique notification identification number (e.g., Notification_01, Notification_02). If a unique notification number was provided with a notification received under the provisions of § 60.5371, 60.5371a, or 60.5371b of this chapter, an applicable approved state plan, or applicable Federal plan in part 62 of this chapter, report the number associated with the event provided in the notification. (ii) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only) to which the notification was attributed. (iii) Based on any assessment or investigation triggered by the notification, indicate if the emissions were from normal operations, a planned maintenance event, leaking equipment, malfunctioning equipment or device, or undetermined cause. (iv) An indication of whether the emissions identified via the notification are included in annual emissions reported under this subpart and, if so, the source type under which the emissions identified via the notification are reported (from the list of source types required to be reported as specified in § 98.232 for the facility's applicable industry segment). If the emissions were reported following the requirements of § 98.233(y) as an other large release event, report the unique release event identification number assigned to the other large release event as reported in paragraph (y)(2) of this section. If the emissions identified via the notification are not included in the annual emissions reported under this subpart, you must provide certification that the facility does not own or operate the equipment at the location identified in the notification as specified in § 98.233(y)(6)(i) or provide certification that the facility conducted a complete investigation of the site as specified in § 98.233(y)(6)(ii) and does not own or operate the emitting equipment at the location identified in the notification. (v) Provide an indication if you received a super-emitter release notification from the EPA after December 31 of the reporting year for which investigations are on-going such that the annual report that has been submitted may be revised and resubmitted pending the outcome of the super-emitter investigation. (z) Combustion equipment. (1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) through (iii) of this section for each unit type. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) The type of combustion unit. (iii) The total number of combustion units. (2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. For each type of combustion unit at your facility, you must report the information specified in paragraphs (z)(2)(i) through (iv) and (z)(2)(viii) through (x) of this section, except for internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower) or internal fuel combustion units of any heat capacity that are compressor-drivers that combust natural gas meeting the criteria in § 98.233(z)(1) or (2) or a fuel meeting the criteria in § 98.233(z)(3), which must report the information specified in paragraphs (z)(2)(i) through (x) of this section. Information must be reported for each combustion unit type, fuel type, and method for determining the CH 4 (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) The type of combustion unit including external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers. (iii) The type of fuel combusted. (iv) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons. (v) The equipment type, including reciprocating 2-stroke-lean burn, reciprocating 4-stroke lean-burn, reciprocating 4-stroke rich-burn, and gas turbine. (vi) The method used to determine the methane emission factor, including the default emission factor from table W-7 to this subpart, OEM data, or performance tests in § 98.234(i) for natural gas described in § 98.233(z)(1) or (2), or performance tests in § 98.234(i) or default combustion efficiency for fuels described in section § 98.233(z)(3). (vii) The value of the CH 4 4 4 4 4 (viii) Annual CO 2 2 (ix) Annual CH 4 4 (x) Annual N 2 2 (aa) Industry segment-specific information. (1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (iv) of this section. (i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole, unless otherwise specified. (A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production. (B) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet. (C) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels. (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category. (A) State. (B) County. (C) Formation type. (D) The number of producing wells at the end of the calendar year (exclude only those wells permanently shut-in and plugged). (E) The number of producing wells acquired during the calendar year. (F) The number of producing wells divested during the calendar year. (G) The number of wells completed during the calendar year. (H) The number of wells permanently shut-in and plugged during the calendar year. (I) Average mole fraction of CH 4 (J) Average mole fraction of CO 2 (K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel. (L) If an oil sub-basin, report the average API gravity of all wells. (M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge. (iii) Report the information specified in paragraphs (aa)(1)(iii)(A) through (D) of this section for each well located in the facility. (A) Well ID number. (B) Well-pad ID. (C) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet. (D) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels. (iv) Report the information specified in paragraphs (aa)(1)(iv)(A) through (C) of this section for each well-pad site located in the facility. (A) A unique name or ID number for the well-pad. (B) Sub-basin ID. (C) The latitude and longitude of the well-pad representing the geographic centroid or center point of the well-pad in decimal degrees to at least four digits to the right of the decimal point. (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through (iv) of this section. (i) The quantity of natural gas produced from producing wells that is sent to sale in the calendar year, in thousand standard cubic feet. (ii) The quantity of crude oil and condensate produced from producing wells that is sent to sale in the calendar year, in barrels. (iii) For each well permanently shut-in and plugged during the calendar year, the quantity of natural gas produced that is sent to sale in the calendar year, in thousand standard cubic feet. (iv) For each well permanently shut-in and plugged during the calendar year, the quantity of crude oil and condensate produced that is sent to sale in the calendar year, in barrels. (3) For natural gas processing, if your facility fractionates NGLs and also reported as a supplier to subpart NN of this part under the same e-GGRT identification number in the calendar year, you must report the information specified in paragraphs (aa)(3)(ii) and (aa)(3)(v) through (ix) of this section. Otherwise, report the information specified in paragraphs (aa)(3)(i) through (ix) of this section. (i) The quantity of natural gas received at the gas processing plant for processing in the calendar year, in thousand standard cubic feet. (ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet. (iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels. (iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels. (v) Average mole fraction of CH 4 (vi) Average mole fraction of CO 2 (vii) Indicate whether the facility fractionates NGLs. (viii) Indicate whether the facility reported as a supplier to subpart NN of this part under the same e-GGRT identification number in the calendar year. (ix) The quantity of residue gas leaving that has been processed by the facility and any gas that passes through the facility to sales without being processed by the facility. (4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section. (i) The quantity of natural gas transported through the compressor station in the calendar year, in thousand standard cubic feet. (ii) Number of compressors. (iii) Total compressor power rating of all compressors combined, in horsepower. (iv) Average upstream pipeline pressure, in pounds per square inch gauge. (v) Average downstream pipeline pressure, in pounds per square inch gauge. (5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section. (i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of natural gas withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (6) For LNG import equipment, report the quantity of LNG imported that is sent to sale in the calendar year, in thousand standard cubic feet. (7) For LNG export equipment, report the quantity of LNG exported that is sent to sale in the calendar year, in thousand standard cubic feet. (8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section. (i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of LNG withdrawn from storage and sent to sale in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (9) [Reserved] (10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (v) of this section. (i) The quantity of gas received by the gathering and boosting facility in the calendar year, in thousand standard cubic feet. (ii) The quantity of natural gas transported from the gathering and boosting facility in the calendar year, in thousand standard cubic feet. (iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, in barrels. (iv) The quantity of all hydrocarbon liquids transported from the gathering and boosting facility in the calendar year, in barrels. (v) Report the information specified in paragraphs (aa)(10)(v)(A) through (E) of this section for each gathering and boosting site located in the facility for which there were emissions in the calendar year. (A) A unique name or ID number for the gathering and boosting site. (B) Gathering and boosting site type (gathering compressor station, centralized oil production site, gathering pipeline, or other fence-line site). (C) State. (D) For gathering compressor stations, centralized oil production sites, and other fence-line sites, county. (E) For gathering compressor stations, centralized oil production sites, and other fence-line sites, the latitude and longitude of the gathering and boosting site representing the geographic centroid or center point of the site in decimal degrees to at least four digits to the right of the decimal point. (11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section. (i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report. (ii) The quantity of natural gas withdrawn from underground natural gas storage and LNG storage (regasification) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet. (iii) The quantity of natural gas added to underground natural gas storage and LNG storage (liquefied) facilities owned and operated by the onshore natural gas transmission pipeline owner or operator that are not subject to this subpart in the calendar year, in thousand standard cubic feet. (iv) The quantity of natural gas transported through the facility and transferred to third parties such as LDCs or other transmission pipelines, in thousand standard cubic feet. (v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousand standard cubic feet. (vi) The miles of transmission pipeline for each state in the facility. (bb) Missing data. (1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours. (2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element. (cc) Delay in reporting for wildcat wells and delineation wells. 1 2 3 (dd) Drilling mud degassing. (1) For each well for which you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(1)(i) through (viii) of this section. (i) Well ID number. (ii) Approximate total depth below surface, in feet. (iii) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled. (iv) Total time that drilling mud is circulated in the well (T r p 4 s,CH4,r (v) The composition of the drilling mud: water-based, oil-based, or synthetic. (vi) If the well is not a representative well, Well ID number of the representative well used to derive the CH 4 4 (vii) If the well is a representative well, report the information specified in paragraphs (dd)(1)(vi)(A) through (D) of this section. (A) Average mud rate (MR r 4 s,CH4,r (B) Average concentration of natural gas in the drilling mud (X n (C) Measured mole fraction for CH 4 CH4 4 (D) Calculated CH 4 s,CH4,r 4 s,CH4,r 4 (viii) Annual CH 4 4 (2) For each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(2)(i) through (iv) of this section. (i) Well ID number. (ii) Total number of drilling days (DD p (iii) The composition of the drilling mud: water-based, oil-based, or synthetic. (iv) Annual CH 4 4 (3) For each well for which you used Calculation Method 3 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(i) through (iv) of this section. (i) Well ID number. (ii) For the time periods you used Calculation Method 1 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(ii)(A) through (G) of this section. (A) Approximate total depth below surface, in feet. (B) Target hydrocarbon-bearing stratigraphic formation to which the well is drilled. (C) Total time that drilling mud is circulated in the well (T r p 4 s,CH4,r (D) The composition of the drilling mud: water-based, oil-based, or synthetic. (E) If the well is not a representative well, Well ID number of the representative well used to derive the CH 4 4 (F) If the well is a representative well, report the information specified in paragraphs (dd)(3)(ii)(F)( 1 4 ( 1 r 4 s,CH4,r ( 2 n ( 3 4 CH4 4 ( 4 4 s,CH4,r 4 s,CH4,r 4 (G) Annual CH 4 4 (iii) For the time periods for each well for which you used Calculation Method 2 to calculate natural gas emissions from mud degassing, report the information specified in paragraphs (dd)(3)(iii)(A) through (C) of this section. (A) Total number of drilling days (DD p (B) The composition of the drilling mud: water-based, oil-based, or synthetic. (C) Annual CH 4 4 (iv) Total annual CH 4 4 4 (ee) Crankcase vents. 4 (1) The information and number of reciprocating internal combustion engines with crankcase vents as specified in paragraphs (ee)(1)(i) through (v) of this section, as applicable. If a reciprocating internal combustion engine with crankcase vents was vented directly to the atmosphere for part of the year and routed to a flare during another part of the year, then include the engine in each of the applicable counts specified in paragraphs (ee)(1)(iii) and (iv) of this section. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) The total number of reciprocating internal combustion engines with crankcase vents. (iii) The total number of reciprocating internal combustion engines with crankcase vents that operated and were vented directly to the atmosphere. (iv) The total number of reciprocating internal combustion engines with crankcase vents that operated and were routed to a flare. (v) The total number of reciprocating internal combustion engines with crankcase vents that were in a manifolded group containing a compressor vent source with emissions reported under paragraph (o) or (p) of this section. (2) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(1) must report the information specified in paragraphs (ee)(2)(i) and (ii) of this section, as applicable. (i) For each measurement performed on a crankcase vent, report the information specified in paragraphs (ee)(2)(i)(A) through (F) of this section. (A) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (B) Unique name or ID for the reciprocating internal combustion engine. (C) Measurement date. (D) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions. (E) Measured flow rate, in standard cubic feet per hour. (F) If the measurement is for a manifolded group of crankcase vent sources, indicate the number of reciprocating internal compressor engines that were operating during measurement. (ii) Annual CH 4 4 (3) Reciprocating internal combustion engines with crankcase vents that calculate emissions according to § 98.233(ee)(2) must report the information specified in paragraphs (ee)(3)(i) through (iv) of this section. (i) Well-pad ID (for the onshore petroleum and natural gas production industry segment only) or gathering and boosting site ID (for the onshore petroleum and natural gas gathering and boosting industry segment only). (ii) Total number of reciprocating internal combustion engines with crankcase vents that were operational at some point in the calendar year at the well-pad site, gathering and boosting site, or facility, as applicable. (iii) Total time that the reciprocating internal combustion engines with crankcase venting were operational in the calendar year, in hours (“T” in equation W-46 to § 98.233). (iv) Annual CH 4 4 [79 FR 70411, Nov. 24, 2014, as amended at 80 FR 64291, Oct. 22, 2015; 81 FR 86515, Nov. 30, 2016; 89 FR 42289, 42293, May 14, 2024; 89 FR 71846, 71848, Sept. 4, 2024] § 98.237 Records that must be retained. Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by § 98.3(g), you must retain the following records: (a) Dates on which measurements were conducted. (b) Results of all emissions detected and measurements. (c) Calibration reports for detection and measurement instruments used. (d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions. (e) The records required under § 98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart. (f) For each time a missing data procedure was used, keep a record listing the emission source type, a description of the circumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to develop the substitute value, and the substitute value. (g) For each situation when you fail to fully conform with all cited provisions in either § 98.233(n)(1)(i) or (ii) for a period of 15 consecutive days and you utilized the Tier 3 default destruction and combustion efficiency values, you must document these periods when the non-conformance began, and the date when full conformance was re-established. [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 79 FR 70424, Nov. 25, 2014; 89 FR 42321, May 14, 2024] § 98.238 Definitions. Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Acid gas 2 2 Acid gas removal unit Acid gas removal unit (AGR) vent emissions e.g. Associated gas venting or flaring Associated with a single well-pad Atmospheric pressure storage tank e.g. Automated liquids unloading Basin Centralized oil production site centralized oil production site Compressor 2 2 2 Compressor mode Compressor source Condensate Crankcase venting e.g. Delineation well Distribution pipeline Drilling mud Drilling mud degassing Enclosed combustion device Engineering estimation, Enhanced oil recovery Equivalent stratigraphic interval External combustion Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements Facility with respect to onshore petroleum and natural gas gathering and boosting for purposes of reporting under this subpart and for the corresponding subpart A requirements Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements 2 Facility with respect to the onshore natural gas transmission pipeline segment Farm Taps Field Flare, Flare combustion efficiency Flare stack emissions 2 2 4 2 Forced extraction of natural gas liquids Gathering and boosting site Gathering and boosting system Gathering and boosting system owner or operator Gathering compressor station gathering compressor station Gathering pipeline site gathering pipeline site Horizontal well In vacuum service Internal combustion Liquefied natural gas (LNG) LNG boil-off gas Manifolded compressor source Manifolded group of compressor sources Manual liquids unloading Meter/regulator run Metering-regulating station Mud rate Natural gas Nitrogen removal unit e.g. Nitrogen removal unit vent emissions Offshore Onshore natural gas transmission pipeline owner or operator Onshore petroleum and natural gas production owner or operator Operating pressure Other large release event Other large release events Other large release events Other large release events Pressure groups Produced water Pump Pump seals Pump seal emissions Reduced emissions completion Reduced emissions workover i.e., Reservoir Residue Gas Residue Gas Compression Routed to combustion routed to combustion Separator Sub-basin category, for onshore natural gas production, Target hydrocarbon-bearing stratigraphic formation Transmission company interconnect M&R station Transmission-distribution (T-D) transfer station Transmission pipeline Tubing diameter groups Tubing systems Turbine meter Vented emissions 4 2 Vertical well Well blowout Well identification (ID) number Well-pad site Well release Well testing venting and flaring Wildcat well [75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80590, Dec. 23, 2011; 79 FR 63794, Oct. 24, 2014; 79 FR 70424, Nov. 25, 2014; 80 FR 64296, Oct. 22, 2015; 89 FR 42321-22, May 14, 2024] Table W-1 to Subpart W of Part 98—Default Whole Gas Population Emission Factors Industry segment Source type/component Emission factor Population Emission Factors—Pneumatic Device Vents and Pneumatic Pumps, Gas Service 1 • Onshore petroleum and natural gas production Continuous Low Bleed Pneumatic Device Vents 2 6.8 • Onshore petroleum and natural gas gathering and boosting Continuous High Bleed Pneumatic Device Vents 2 21 Intermittent Bleed Pneumatic Device Vents 2 8.8 Pneumatic Pumps 3 13.3 • Onshore natural gas processing Continuous Low Bleed Pneumatic Device Vents 2 6.8 • Onshore natural gas transmission compression Continuous High Bleed Pneumatic Device Vents 2 30 • Underground natural gas storage Intermittent Bleed Pneumatic Device Vents 2 2.3 • Natural gas distribution Population Emission Factors—Major Equipment, Gas Service 1 • Onshore petroleum and natural gas production Wellhead 8.87 • Onshore petroleum and natural gas gathering and boosting Separator 9.65 Meters/Piping 7.04 Compressor 13.8 Dehydrator 8.09 Heater 5.22 Storage Vessel 1.83 Population Emission Factors—Major Equipment, Crude Service Onshore petroleum and natural gas production Wellhead 4.13 Separator 4.77 Meters/Piping 12.4 Compressor 13.8 Dehydrator 8.09 Heater 3.2 Storage Vessel 1.91 Population Emission Factors—Gathering Pipelines, by Material Type 4 Onshore petroleum and natural gas gathering and boosting Protected Steel 0.93 Unprotected Steel 8.2 Plastic/Composite 0.28 Cast Iron 8.4 1 2 3 4 [89 FR 42323, May 14, 2024] Table W-2 to Subpart W of Part 98—Default Whole Gas Leaker Emission Factors Equipment components Emission factor (scf whole gas/hour/component) If you survey using Method 21 as specified in § 98.234(a)(2)(i) If you survey using Method 21 as specified in § 98.234(a)(2)(ii) If you survey using any of the methods in § 98.234(a)(1), (3), or (5) Leaker Emission Factors—Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting—All Components, Gas Service Valve 9.6 5.5 16 Flange 6.9 4.0 11 Connector (other) 4.9 2.8 7.9 Open-Ended Line 1 6.3 3.6 10 Pressure Relief Valve 7.8 4.5 13 Pump Seal 14 8.3 23 Other 2 9.1 5.3 15 Leaker Emission Factors—Onshore Petroleum and Natural Gas Production—All Components, Oil Service Valve 5.6 3.3 9.2 Flange 2.7 1.6 4.4 Connector (other) 5.6 3.2 9.1 Open-Ended Line 1.6 0.93 2.6 Pump 3 3.7 2.2 6.0 Other 2 2.2 1.0 2.9 1 2 3 [89 FR 42324, May 14, 2024] Table W-3 to Subpart W of Part 98—Default Total Hydrocarbon Population Emission Factors Industry segment Source type/component Emission factor Population Emission Factors—Storage Wellheads, Gas Service Underground natural gas storage Connector 0.01 Valve 0.1 Pressure Relief Valve 0.17 Open-Ended Line 0.03 [89 FR 42325, May 14, 2024] Table W-4 to Subpart W of Part 98—Default Total Hydrocarbon Leaker Emission Factors Equipment components Emission factor If you survey using Method 21 as specified in § 98.234(a)(2)(i) If you survey using Method 21 as specified in § 98.234(a)(2)(ii) If you survey using any of the methods in § 98.234(a)(1), (3), or (5) Leaker Emission Factors—Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression—Compressor Components, Gas Service Valve 1 14.84 9.51 24.2 Connector 5.59 3.58 9.13 Open-Ended Line 17.27 11.07 28.2 Pressure Relief Valve 39.66 25.42 64.8 Meter 19.33 12.39 31.6 Other 2 4.1 2.63 6.70 Leaker Emission Factors—Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression—Non-Compressor Components, Gas Service Valve 1 6.42 4.12 10.5 Connector 5.71 3.66 9.3 Open-Ended Line 11.27 7.22 18.4 Pressure Relief Valve 2.01 1.29 3.28 Meter 2.93 1.88 4.79 Other 2 4.1 2.63 6.70 Leaker Emission Factors—Underground Natural Gas Storage—Storage Station, Gas Service Valve 1 14.84 9.51 24.2 Connector (other) 5.59 3.58 9.13 Open-Ended Line 17.27 11.07 28.2 Pressure Relief Valve 39.66 25.42 64.8 Meter and Instrument 19.33 12.39 31.6 Other 2 4.1 2.63 6.70 Leaker Emission Factors—Underground Natural Gas Storage—Storage Wellheads, Gas Service Valve 1 4.5 3.2 7.35 Connector (other than flanges) 1.2 0.7 1.96 Flange 3.8 2.0 6.21 Open-Ended Line 2.5 1.7 4.08 Pressure Relief Valve 4.1 2.5 6.70 Other 2 4.1 2.5 6.70 1 2 [89 FR 42325, May 14, 2024] Table W-5 to Subpart W of Part 98—Default Methane Population Emission Factors Industry segment Source type/component Emission Population Emission Factors—LNG Storage Compressor, Gas Service LNG storage Vapor Recovery Compressor 1 4.17 LNG import and export equipment Population Emission Factors—Below Grade Transmission-Distribution Transfer Station Components and Below Grade Metering-Regulating Station 2 Components, Gas Service 3 Natural gas distribution Below Grade T-D Transfer Station 0.30 Below Grade M&R Station 0.30 Population Emission Factors—Distribution Mains, Gas Service 4 Natural gas distribution Unprotected Steel 5.1 Protected Steel 0.57 Plastic 0.17 Cast Iron 6.9 Population Emission Factors—Distribution Services, Gas Service 5 Natural gas distribution Unprotected Steel 0.086 Protected Steel 0.0077 Plastic 0.0016 Copper 0.03 Population Emission Factors—Interconnect, Direct Sale, or Farm Tap Stations 2 3 Onshore natural gas transmission pipeline Transmission Company Interconnect M&R Station 166 Direct Sale or Farm Tap Station 1.3 Population Emission Factors—Transmission Pipelines, Gas Service 4 Onshore natural gas transmission pipeline Unprotected Steel 0.74 Protected Steel 0.041 Plastic 0.061 Cast Iron 27 1 2 3 4 5 [89 FR 42326, May 14, 2024] Table W-6 to Subpart W of Part 98—Default Methane Leaker Emission Factors Equipment components Emission If you survey using Method 21 as specified in § 98.234(a)(2)(i) If you survey using Method 21 as specified in § 98.234(a)(2)(ii) If you survey using any of the methods in § 98.234(a)(1), (3), or (5) Leaker Emission Factors—LNG Storage and LNG Import and Export Equipment—Storage Components and Terminals Components, LNG Service Valve 1.19 0.23 1.94 Pump Seal 4.00 0.73 6.54 Connector 0.34 0.11 0.56 Other 1 1.77 0.99 2.9 Leaker Emission Factors—LNG Storage and LNG Import and Export Equipment—Storage Components and Terminals Components, Gas Service Valve 2 14.84 9.51 24.2 Connector 5.59 3.58 9.13 Open-Ended Line 17.27 11.07 28.2 Pressure Relief Valve 39.66 25.42 64.8 Meter and Instrument 19.33 12.39 31.6 Other 3 4.1 2.63 6.70 Leaker Emission Factors—Natural Gas Distribution—Transmission-Distribution Transfer Station 4 Components, Gas Service Connector 1.69 2.76 Block Valve 0.557 0.91 Control Valve 9.34 15.3 Pressure Relief Valve 0.27 0.44 Orifice Meter 0.212 0.35 Regulator 0.772 1.26 Open-ended Line 26.131 42.7 1 2 3 4 [89 FR 42327, May 14, 2024] Table W-7 to Subpart W of Part 98—Default Methane Emission Factors for Internal Combustion Equipment Internal combustion Emission 4 Reciprocating Engine, 2-stroke lean-burn 0.658 Reciprocating Engine, 4-stroke lean-burn 0.522 Reciprocating Engine, 4-stroke rich-burn 0.045 Gas Turbine 0.004 [89 FR 42327, May 14, 2024] Subpart X—Petrochemical Production § 98.240 Definition of the source category. (a) The petrochemical production source category consists of processes as described in paragraphs (a)(1) and (2) of this section. (1) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, as either an intermediate in the on-site production of other chemicals or as an end product for sale or shipment off site, except as specified in paragraphs (b) through (g) of this section. (2) When ethylene dichloride and vinyl chloride monomer are produced in an integrated process, you may consider the entire integrated process to be the petrochemical process for the purpose of complying with the mass balance option in § 98.243(c). If you elect to consider the integrated process to be the petrochemical process, then the mass balance must be performed over the entire integrated process. (b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category. (c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and methanol. (d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category. (e) A process that produces bone black is not part of the petrochemical source category. (f) A process that produces a petrochemical from bio-based feedstock is not part of the petrochemical production source category. (g) A process that solely distills or recycles waste solvent that contains a petrochemical is not part of the petrochemical production source category. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 76 FR 80590, Dec. 23, 2011; 81 FR 89260, Dec. 9, 2016] § 98.241 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in § 98.240, and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.242 GHGs to report. You must report the information in paragraphs (a) through (c) of this section: (a) CO 2 4 2 2 (1) If you comply with § 98.243(b) or (d), report under this subpart the calculated CO 2 4 2 2 (2) If you comply with § 98.243(c), report under this subpart the calculated CO 2 (b) CO 2 4 2 (1) If you comply with § 98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C. (2) If you comply with § 98.243(c), report CO 2 4 2 (c) CO 2 2 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71960, Nov. 29, 2013] § 98.243 Calculating GHG emissions. (a) If you route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and use CEMS on each stack to measure CO 2 (b) Continuous emission monitoring system (CEMS). (1) Determine CO 2 (2) For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH 4 2 (3) For each flare, calculate CO 2 4 2 (c) Mass balance for each petrochemical process unit. 2 (1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in § 98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in § 98.244(b)(3). Fuels used for combustion purposes are not considered to be feedstocks. (2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in § 98.244(b)(1). (3) Collect a sample of each feedstock and product at least once per month and determine the molecular weight (for gaseous materials when the quantity is measured in scf) and carbon content of each sample according to the procedures of § 98.244(b)(4). If multiple valid molecular weight or carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a feedstock supplier, or product customer, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in § 98.244(b)(4). (4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume or mass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may determine molecular weight and carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section. (i) Calculate the molecular weight and carbon content assuming 100 percent of that feedstock or product is the specific compound. (ii) Maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information. (iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. Keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method. (5) Calculate the CO 2 (i) Gaseous feedstocks and products. Where: C g 2 (F gf i,n f i,n (CC gf i,n (MW f i,n MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68 °F and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole at 60 °F and 14.7 pounds per square inch absolute). (P gp i,n p i,n (CC gp i,n 2 (MW p i,n j = Number of feedstocks. k = Number of products. (ii) Liquid feedstocks and products. Where: C l (F lf i,n (CC lf i,n (P lp i,n (CC lp i,n j = Number of feedstocks. k = Number of products. (iii) Solid feedstocks and products. Where: C s (F sf i,n (CC sf i,n (P sp i,n (CC sp i,n j = Number of feedstocks. k = Number of products. (iv) Annual emissions. 2 Where: CO 2 2 0.001 = Conversion factor from kg to metric tons. 44 = Molecular weight of CO 2 12 = Atomic weight of carbon (C) (kg/kg-mole). (d) Optional combustion methodology for ethylene production processes. (1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO 2 (2) You may use either Equation C-1 or Equation C-2a in subpart C of this part to calculate CO 2 (i) The annual average flow rate of fuel gas (that contains ethylene process off-gas) in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute, and a flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year. (ii) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that contains ethylene process off-gas) or an upstream common pipe. (3) Except as specified in paragraph (d)(5) of this section, calculate CH 4 2 2 (i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for “Fuel Gas” in Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources). (ii) For Tier 3, use either the default high heat value for fuel gas in Table C-1 of subpart C of this part or a calculated HHV, as allowed in Equation C-8 of subpart C of this part. (4) You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas. (5) For each flare, calculate CO 2 4 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79157, Dec. 17, 2010; 78 FR 71961, Nov. 29, 2013; 81 FR 89260, Dec. 9, 2016; 89 FR 31929, Apr. 25, 2024] § 98.244 Monitoring and QA/QC requirements. (a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in § 98.34(c). (b) If you use the mass balance methodology in § 98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents. (1) Operate, maintain, and calibrate belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see § 98.7), or follow procedures specified by the measurement device manufacturer. You must recalibrate each weighing device according to one of the following frequencies. You may recalibrate either at the minimum frequency specified by the manufacturer or biennially ( i.e., (2) Operate and maintain all flow meters used for gas and liquid feedstocks and products according to the manufacturer's recommended procedures. You must calibrate each of these flow meters as specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section: (i) You may use either the calibration methods specified by the flow meter manufacturer or an industry consensus standard method. Each flow meter must meet the applicable accuracy specification in § 98.3(i), except as otherwise specified in §§ 98.3(i)(4) through (i)(6). (ii) You must recalibrate each flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used. (3) You must perform tank level measurements (if used to determine feedstock or product flows) according to one of the following methods. You may use any standard method published by a consensus-based standards organization or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org, http://www.api.org (4) Beginning January 1, 2010, use any applicable methods specified in paragraphs (b)(4)(i) through (xv) of this section to determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products. Calibrate instruments in accordance with paragraphs (b)(4)(i) through (xv) of this section, as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (xv) of this section may be performed by the owner or operator, by an independent laboratory, by the supplier of a feedstock, or by a product customer. (i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see (ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph (incorporated by reference, see (iii) ASTM D2505-88 (Reapproved 2004)e1 (incorporated by reference, see § 98.7). (iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see (v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference, see (vi) 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 (vii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A (all incorporated by reference, see § 98.7). (ix) Method 18 at 40 CFR part 60, appendix A-6. (x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of the rule. (xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography (incorporated by reference, see § 98.7). (xii) ASTM D7633-10 Standard Test Method for Carbon Black—Carbon Content (incorporated by reference, see § 98.7). (xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions. (xiv) The results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions. (xv) Beginning on January 1, 2010, the methods specified in paragraphs (b)(4)(xv)(A) and (B) of this section may be used as alternatives for the methods specified in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section. (A) An industry standard practice or a method published by a consensus-based standards organization if such a method exists for carbon black feedstock oils and carbon black products. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.naesb.org (B) Modifications of existing analytical methods or other methods that are applicable to your process provided that the methods listed in paragraphs (b)(4)(i) through (b)(4)(xiv) 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. (c) If you comply with § 98.243(b) or (d), conduct monitoring and QA/QC for flares in accordance with § 98.254(b) through (e) for each flare gas flow meter, gas composition meter, and/or heating value monitor that you use to comply with § 98.253(b)(1) through (b)(3). You must implement all applicable QA/QC requirements specified in this paragraph (c) beginning no later than January 1, 2015. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79158, Dec. 17, 2010; 78 FR 71961, Nov. 29, 2013; 89 FR 31929, Apr. 25, 2024] § 98.245 Procedures for estimating missing data. For missing feedstock and product flow rates, use the same procedures as for missing fuel usage as specified in § 98.35(b)(2). For missing feedstock and product carbon contents and missing molecular weights for gaseous feedstocks and products, use the same procedures as for missing carbon contents and missing molecular weights for fuels as specified in § 98.35(b)(1). For missing flare data, follow the procedures in § 98.255(b) and (c). [78 FR 71962, Nov. 29, 2013] § 98.246 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit. (a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (15) of this section for each type of petrochemical produced, reported by process unit. (1) The petrochemical process unit ID number or other appropriate descriptor. (2) The type of petrochemical produced. (3) Annual CO 2 (4) The temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X-1 of § 98.243 were determined. (5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the portion of the total amount of ethylene dichloride (EDC) produced that is used in vinyl chloride monomer (VCM) production may be a measured quantity or an estimate that is based on process knowledge and best available data. The portion of the total amount of EDC produced that is not utilized in VCM production must be measured in accordance with § 98.244(b)(2) or (3). Sum the amount of EDC used in the production of VCM plus the amount of separate EDC product to report as the total quantity of EDC petrochemical from an integrated EDC/VCM petrochemical process unit. (6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section. (i) Name of each method used to determine carbon content or molecular weight in accordance with § 98.244(b)(4); (ii) Description of each type of measurement device ( e.g., (iii) Identification of each method ( i.e., (7) [Reserved] (8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit. (9) The number of days during which off-specification product was produced if the alternative to sampling and analysis specified in § 98.243(c)(4) is used for a product, and, if applicable, the date of any process change that reduced the monthly average composition to less than 99.5 percent for each product or feedstock for which you comply with the alternative to sampling and analysis specified in § 98.243(c)(4). (10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation. (11) If you determine carbon content or composition of a feedstock or product using a method under § 98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports. (i) Name or title of the analytical method. (ii) A copy of the method. If the method is a modification of a method listed in §§ 98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the listed method. (iii) An explanation of why an alternative to the methods listed in §§ 98.244(b)(4)(i) through (xiv) is needed. (12) Name and annual quantity (in metric tons) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of § 98.243. (13) Name and annual quantity (in metric tons) of each product included in equations X-1, X-2, and X-3 to § 98.243. If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the reported quantity of EDC product should include only that which was not used in the VCM process. (14) Annual average of the measurements or determinations of the carbon content of each feedstock and product, conducted according to § 98.243(c)(3) or (4). (i) For feedstocks and products that are gaseous or solid, report this quantity in kg C per kg of feedstock or product. (ii) For liquid feedstocks and products, report this quantity either in units of kg C per kg of feedstock or product, or kg C per gallon of feedstock or product. (15) For each gaseous feedstock or product for which the volume was used in equation X-1 to § 98.243, report the annual average molecular weight of the measurements or determinations, conducted according to § 98.243(c)(3) or (4). Report the annual average molecular weight in units of kg per kg mole. (b) If you measure emissions in accordance with § 98.243(b), then you must report the information listed in paragraphs (b)(1) through (10) of this section. (1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced. (2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under § 98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Section 98.36(c)(2)(ii), (ix) and (x) do not apply for the purposes of this subpart. (3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under § 98.36(b)(6) and (7), (b)(9)(i) and (ii) and (e)(2)(vi). (4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO 2 2 2 (5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH 4 2 4 2 (6) [Reserved] (7) Information listed in § 98.256(e) for each flare that burns process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO 2 4 2 (8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). (9) Name and annual quantity (in metric tons) of each carbon-containing feedstock. (10) Name and annual quantity (in metric tons) of each product. (c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (6) of this section. (1) The ethylene process unit ID or other appropriate descriptor. (2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in § 98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit. (3) Information listed in § 98.256(e) for each flare that burns ethylene process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO 2 4 2 (4) Name and annual quantity of each carbon-containing feedstock (metric tons). (5) Annual quantity of ethylene produced from each process unit (metric tons). (6) Name and annual quantity (in metric tons) of each product produced in each process unit. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79159, Dec. 17, 2010; 78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014; 81 FR 89260, Dec. 9, 2016; 89 FR 31929, Apr. 25, 2024] § 98.247 Records that must be retained. In addition to the recordkeeping requirements in § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section, as applicable. (a) If you comply with the CEMS measurement methodology in § 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, records of the procedures used to develop estimates of the fraction of total emissions attributable to petrochemical processing and combustion of petrochemical process off-gas as required in § 98.246(b), and records of any annual average HHV calculations. (b) If you comply with the mass balance methodology in § 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (4) of this section. (1) Results of feedstock or product composition determinations conducted in accordance with § 98.243(c)(4). (2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(c)(4) for determining carbon content of product. (3) As part of the monitoring plan required under § 98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates. (4) The dates and results ( e.g., (c) If you comply with the combustion methodology in § 98.243(d), then you must retain under this subpart the records required for the applicable Tier Calculation Methodologies in § 98.37. If you comply with § 98.243(d)(2), you must also keep records of the annual average flow calculations. (d) Verification software records. (1) Indicate whether the feedstock is measured as mass or volume (Equation X-1 of § 98.243). (2) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-1). (3) Volume of gaseous feedstock introduced per month (scf) (Equation X-1). (4) Mass of gaseous feedstock introduced per month (kg) (Equation X-1). (5) Average carbon content of the gaseous feedstock per month (kg C per kg of feedstock) (Equation X-1). (6) Molecular weight of gaseous feedstock per month (kg per kg-mole) (Equation X-1). (7) Indicate whether the gaseous product is measured as mass or volume (Equation X-1). (8) Volume of gaseous product produced per month (scf) (Equation X-1). (9) Mass of gaseous product produced per month (kg) (Equation X-1). (10) Average carbon content of gaseous product (including streams containing CO 2 (11) Molecular weight of gaseous product per month (kg per kg-mole) (Equation X-1). (12) Molar volume conversion factor of product (scf per kg-mole) (Equation X-1). (13) Indicate whether feedstock is measured as mass or volume (Equation X-2 of § 98.243). (14) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-2). (15) Volume of liquid feedstock introduced per month (gallons) (Equation X-2). (16) Mass of liquid feedstock introduced per month (kg) (Equation X-2). (17) Average carbon content of liquid feedstock per month (kg C per gallon) (Equation X-2). (18) Average carbon content of liquid feedstock per month (kg C per kg of feedstock) (Equation X-2). (19) Indicate whether product is measured as mass or volume per month (Equation X-2). (20) Volume of liquid product produced per month (gallons) (Equation X-2). (21) Mass of liquid product produced per month (kg) (Equation X-2). (22) Average carbon content of liquid product per month, including organic liquid wastes (kg C per gallon) (Equation X-2). (23) Average carbon content of liquid product, including organic liquid wastes (kg C per kg of product) (Equation X-2). (24) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-3 of § 98.243). (25) Mass of solid feedstock introduced per month (kg) (Equation X-3). (26) Average carbon content of solid feedstock per month (kg C per kg of feedstock) (Equation X-3). (27) Mass of solid product produced per month (kg) (Equation X-3). (28) Average carbon content of solid product per month (kg C per kg of product) (Equation X-3). (29) Records required in § 98.257(b)(1) through (8) of this section for each flare that burns ethylene process off-gas. (30) Records required in § 98.37 for each stationary fuel combustion unit (or group of stationary sources with a common pipe) that burns ethylene process off-gas, except flares. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 78 FR 71962, Nov. 29, 2013; 79 FR 63794, Oct. 24, 2014; 81 FR 89261, Dec. 9, 2016] § 98.248 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Product [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71963, Nov. 29, 2013; 81 FR 89261, Dec. 9, 2016] Subpart Y—Petroleum Refineries § 98.250 Definition of source category. (a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of this section. (b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced. (c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; and sulfur recovery plants. [74 FR 56374, Oct. 30, 2009, as amended at 89 FR 31929, Apr. 25, 2024] § 98.251 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.252 GHGs to report. You must report: (a) CO 2 4 2 2 4 2 2 4 2 (1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute and either of the conditions in paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year. (i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. (ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator. (2) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr and either of the following conditions exist: (i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe; or (ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator. (b) CO 2 4 2 (c) CO 2 (d) CO 2 (e) [Reserved] (f) CO 2 4 (g) CH 4 (h) CO 2 4 2 (i) [Reserved] [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013; 89 FR 31929, Apr. 25, 2024] § 98.253 Calculating GHG emissions. (a) Calculate GHG emissions required to be reported in § 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section. (b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare GHG emissions calculations with the exception of the following, which may be excluded as applicable: gas used for the flare pilots, and if using the calculation method in paragraph (b)(1)(iii) of this section, the gas released during start-up, shutdown, or malfunction events of 500,000 scf/day or less. (1) Calculate the CO 2 (i) Flow measurement. (ii) Heat value or carbon content measurement. 2 (A) If you monitor gas composition, calculate the CO 2 where: CO 2 2 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). n = Number of measurement periods. The minimum value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. 44 = Molecular weight of CO 2 12 = Atomic weight of C (kg/kg-mole). (Flare) p p (MW) p MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-mole at 60 °F and 14.7 psia). (CC) p where: CO 2 2 n = Number of measurement periods. The minimum value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. (Flare) p 44 = Molecular weight of CO 2 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). (%CO 2 p 2 y = Number of carbon-containing compounds other than CO 2 x = Index for carbon-containing compounds other than CO 2 0.98 = Assumed combustion efficiency of a flare (mole CO 2 (%C X p CMN X 2 6 3 8 (B) If you monitor heat content but do not monitor gas composition, calculate the CO 2 Where: CO 2 2 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). n = Number of measurement periods. The minimum value for n is 52 (for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. (Flare) p p p p (HHV) p EmF = Default CO 2 2 (iii) Alternative to heat value or carbon content measurements. 2 (A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day. (B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher heating value of the flare gas under normal operations may be estimated from historic data or engineering calculations. (C) Calculate the CO 2 Where: CO 2 2 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). Flare Norm HHV = Higher heating value for fuel gas or flare gas from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf). EmF = Default CO 2 2 n = Number of start-up, shutdown, and malfunction events during the reporting year exceeding 500,000 scf/day. p = Start-up, shutdown, and malfunction event index. 44 = Molecular weight of CO 2 12 = Atomic weight of C (kg/kg-mole). (Flare SSM p (MW) p MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). (CC) p (2) Calculate CH 4 Where: CH 4 4 CO 2 2 EmF CH4 4 4 EmF = Default CO 2 2 0.02/0.98 = Correction factor for flare combustion efficiency. 16/44 = Correction factor ratio of the molecular weight of CH 4 2 f CH4 (3) Calculate N 2 Where: N 2 2 CO 2 2 EmF N2O 2 2 EmF = Default CO 2 2 (c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions from coke burn-off using the applicable methods described in paragraphs (c)(1) through (5) of this section. (1) If you operate and maintain a CEMS that measures CO 2 2 (i) Calculate CO 2 (ii) For catalytic cracking units whose process emissions are discharged through a combined stack with other CO 2 e.g., 2 e.g., 2 (2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO 2 2 2 2 (i) Calculate the CO 2 Where: CO 2 2 Q r %CO 2 2 %CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). When there is no post-combustion device, assume %CO to be zero. 44 = Molecular weight of CO 2 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). 0.001 = Conversion factor (metric ton/kg). n = Number of hours in calendar year. (ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using either Equation Y-7a or Equation Y-7b of this section. where: Q r Q a Q oxy %O 2 %O oxy 2 %CO 2 2 %CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume—dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required under 40 CFR part 63 subpart UUU, assume %CO to be zero. where: Q r Q a Q oxy %N 2,oxy 2 2 %N 2,exhaust 2 (iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 (3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO 2 (i) If you continuously or no less frequently than daily monitor the O 2 2 2 (ii) If you do not monitor at least daily the O 2 2 2 Where: CO 2 2 Q unit CBF = Coke burn-off factor from engineering calculations (kg coke per barrel of feed); default for catalytic cracking units = 7.3; default for fluid coking units = 11. 0.001 = Conversion factor (metric ton/kg). CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 2 (iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO 2 (4) Calculate CH 4 Where: CH 4 CO 2 2 EmF 1 2 2 EmF 2 4 4 (5) Calculate N 2 Where: N 2 2 CO 2 2 EmF 1 2 2 EmF 3 2 2 (d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas. (e) For catalytic reforming units, calculate the CO 2 4 2 (1) If you operate and maintain a CEMS that measures CO 2 2 (2) If you continuously or no less frequently than daily monitor the O 2 2 2 (3) Calculate CO 2 Where: CO 2 2 CB Q n = Number of regeneration cycles or measurement periods in the calendar year. CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO 2 2 0.001 = Conversion factor (metric ton/kg). (f) For on-site sulfur recovery plants and for sour gas sent off site for sulfur recovery, calculate and report CO 2 2 (1) If you operate and maintain a CEMS that measures CO 2 2 2 2 (2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow. (3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20. (4) Calculate the CO 2 Where: CO 2 2 F SG 44 = Molecular weight of CO 2 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). MF C 0.001 = Conversion factor, kg to metric tons. (5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO 2 2 (g) [Reserved] (h) For asphalt blowing operations, calculate CO 2 4 2 4 (1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device, calculate CO 2 4 Where: CO 2 2 2 Q AB EF AB,CO2 2 2 Where: CH 4 4 Q AB EF AB,CH 4 4 4 (2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device, calculate CO 2 4 where: CO 2 2 2 0.98 = Assumed combustion efficiency of the control device. Q AB CEF AB 44 = Molecular weight of CO 2 12 = Atomic weight of C (kg/kg-mole). where: CO 2 2 2 Q AB 0.98 = Assumed combustion efficiency of the control device. EF AB,CO2 2 2 CEF AB 44 = Molecular weight of CO 2 12 = Atomic weight of C (kg/kg-mole). where: CH 4 4 0.02 = Fraction of methane uncombusted in the controlled stream based on assumed 98% combustion efficiency. Q AB EF AB,CH4 4 4 (i) For each delayed coking unit, calculate the CH 4 (1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum) dimensions and typical coke drum outage at the end of the coking cycle using Equation Y-18a of this section. Where: M coke ρ bulk 3 3 H drum H outage i.e., D = Diameter of delayed coking unit vessel (feet). (2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using equation Y-18b to this section. Where: M water r water 3 3 H water f coke M coke r particle 3 3 D = Diameter of delayed coking unit vessel (feet). (3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y-18c or Y-18d of this section, as appropriate, based on the measurement system available. Where: T initial T overhead overhead T bottom bottom Where: T initial P overhead (4) Determine the typical mass of steam generated and released per decoking cycle using Equation Y-18e of this section. Where: M steam f ConvLoss M water C p,water M coke C p,coke T initial T final ΔH vap (5) Calculate the CH 4 Where: CH 4 M steam EmF DCU 4 4 4 N = Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year. 0.001 = Conversion factor (metric ton/kg). (j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO 2 4 2 4 2 4 Where: E X N = Number of venting events per year. P = Index of venting events. (VR) p (MF X p MW X 2 2 4 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). (VT) p 0.001 = Conversion factor (metric ton/kg). (k) For uncontrolled blowdown systems, you must calculate CH 4 4 Where: CH 4 4 Q Ref EF BD 4 16 = Molecular weight of CH 4 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). 0.001 = Conversion factor (metric ton/kg). (l) For equipment leaks, calculate CH 4 (1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS PB96-175401). (2) Use Equation Y-21 of this section. Where: CH 4 N CD N PU1 N PU2 N H2 N FGS (m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH 4 (1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH 4 4 Where: CH 4 0.1 = Default emission factor for storage tanks (metric ton CH 4 Q Ref (2) For storage tanks that process unstabilized crude oil, calculate CH 4 Where: CH 4 Q un ΔP = Pressure differential from the previous storage pressure to atmospheric pressure (pounds per square inch, psi). MF CH4 4 4 995,000 = Correlation Equation factor (scf gas per MMbbl per psi). 16 = Molecular weight of CH 4 MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 °F and 14.7 psia or 836.6 scf/kg-mole at 60 °F and 14.7 psia). 0.001 = Conversion factor (metric ton/kg). (3) You do not need to calculate CH 4 (i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships; (ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere; (iii) Bottoms receivers or sumps; (iv) Vessels storing wastewater; or (v) Reactor vessels associated with a manufacturing process unit. (n) For crude oil, intermediate, or product loading operations for which the vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH 4 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79160, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013; 81 FR 89261, Dec. 9, 2016; 89 FR 31929, Apr. 25, 2024] § 98.254 Monitoring and QA/QC requirements. (a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 (b) All gas flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than those subject to the requirements in paragraph (a) of this section shall be calibrated according to the procedures specified by the manufacturer, or according to the procedures in the applicable methods specified in paragraphs (c) through (g) of this section. In the case of gas flow meters, all gas flow meters must meet the calibration accuracy requirements in § 98.3(i). All gas flow meters, gas composition monitors, and heating value monitors must be recalibrated at the applicable frequency specified in paragraph (b)(1) or (b)(2) of this section. (1) You must recalibrate each gas flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used. (2) You must recalibrate each gas composition monitor and heating value monitor according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, annually, or at the interval specified by the industry standard practice used. (c) For flare or sour gas flow meters and gas flow meters used to comply with the requirements in § 98.253(j), operate, calibrate, and maintain the flow meter according to one of the following. You may use the procedures specified by the flow meter manufacturer, or a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic or direct mass spectrometer analysis of the gas may be used, provided that the gas chromatograph or mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph or mass spectrometer are documented in the written Monitoring Plan for the unit under § 98.3(g)(5). (1) Method 18 at 40 CFR part 60, appendix A-6. (2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see (3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see (4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see (6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7). (e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the gas may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5). (1) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see (2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see (3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see (4) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see (5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see (f) For gas flow meters used to comply with the requirements in § 98.253(c)(2)(ii), install, operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 63.1572(c) and the following requirements. (1) Locate the flow monitor at a site that provides representative flow rates. Avoid locations where there is swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. (2) [Reserved] (3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in § 98.6). (g) For exhaust gas CO 2 2 (h)-(i) [Reserved] (j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility. (k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer's instructions. (l) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79163, Dec. 17, 2010; 81 FR 89263, Dec. 9, 2016; 89 FR 31930, Apr. 25, 2024] § 98.255 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations. (a) For stationary combustion sources, use the missing data procedures in subpart C of this part. (b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (c) For missing CO 2 2 4 2 (d) [Reserved] [74 FR 56374, Oct. 30, 2009, as amended at 89 FR 31931, Apr. 25, 2024] § 98.256 Data reporting requirements. In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (q) of this section. (a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources). (b)-(d) [Reserved] (e) For flares, owners and operators shall report: (1) The flare ID number (if applicable). (2) A description of the type of flare (steam assisted, air-assisted). (3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery system. (4) The calculated CO 2 4 2 (5) A description of the method used to calculate the CO 2 (6) If you use Equation Y-1a in § 98.253, an indication of whether daily or weekly measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), or the annual mass of flare gas combusted (in kg/yr). (7) If you use Equation Y-1b of § 98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO 2 2 2 (i) The annual average concentration of the compound (volume or mole percent). (ii) [Reserved] (8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in million (MM) scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted and the annual average higher heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia. (9) If you use Equation Y-3 of § 98.253, the number of SSM events exceeding 500,000 scf/day. (10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of § 98.253. (f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report: (1) The unit ID number (if applicable). (2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit). (3) Maximum rated throughput of the unit, in bbl/stream day. (4) The calculated CO 2 4 2 (5) A description of the method used to calculate the CO 2 (6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO 2 2 2 2 e.g., (7) If you use Equation Y-6 of § 98.253, the annual average exhaust gas flow rate, %CO 2 (8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O 2 oxy 2 (9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %N 2,oxy 2,exhaust. (10) If you use Equation Y-8 of § 98.253, the basis for the value of the average carbon content of coke. (11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH 4 4 (12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N 2 2 (13) If you use Equation Y-11 of § 98.253, the number of regeneration cycles or measurement periods during the reporting year and the average coke burn-off quantity per cycle or measurement period. (g) For fluid coking unit of the flexicoking type, the owner or operator shall report: (1) The unit ID number (if applicable). (2) A description of the type of unit. (3) Maximum rated throughput of the unit, in bbl/stream day. (4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c). (5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO 2 4 2 (h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report: (1) The plant ID number (if applicable). (2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO 2 2 (3) The calculated CO 2 2 (4) [Reserved] (5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for CO 2 (i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit-specific correction was used, report the value of the correction and the approach used. (ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section. (A) The annual volume of recycled tail gas (in scf/year). (B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas). (6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO 2 2 2 (7) If you use the process vent method in § 98.253(j) for a non-Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section. (i) [Reserved] (j) For asphalt blowing operations, the owner or operator shall report: (1) The unit ID number (if applicable). (2) Maximum rated throughput of the unit, in metric tons asphalt/stream day. (3) The type of control device used to reduce methane (and other organic) emissions from the unit. (4) The calculated annual CO 2 4 (5) If you use Equation Y-14 of § 98.253, the basis for the CO 2 (6) If you use Equation Y-15 of § 98.253, the basis for the CH 4 (7) If you use Equation Y-16a of § 98.253, the basis for the carbon emission factor used. (8) If you use Equation Y-16b of § 98.253, the basis for the CO 2 (9) If you use Equation Y-17 of § 98.253, the basis for the CH 4 (10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section. (k) For each delayed coking unit, the owner or operator shall report: (1) The unit ID number (if applicable). (2) Maximum rated throughput of the unit, in bbl/stream day. (3) Annual quantity of coke produced in the unit during the reporting year, in metric tons. (4) The calculated annual CH 4 4 (5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit. (6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using equation Y-18a to § 98.253). If you use mass measurements from company records to determine the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle, you must also report: (i) Internal height of delayed coking unit vessel (feet) for each delayed coking unit. (ii) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed ( i.e. (7) An indication of the method used to estimate the average temperature of the coke bed, T initial (8) An indication of whether a unit-specific methane emissions factor or the default methane emission factor was used for the delayed coking unit. (l) For each process vent subject to § 98.253(j), the owner or operator shall report: (1) The vent ID number (if applicable). (2) The unit or operation associated with the emissions. (3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable. (4) The calculated annual CO 2 4 2 (5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indication of the measurement or estimation method, and for intermittent vents, the number of venting events and the cumulative venting time. (m) For uncontrolled blowdown systems, the owner or operator shall report: (1) An indication of whether the uncontrolled blowdown emission are reported under § 98.253(k) or § 98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems. (2) The cumulative annual CH 4 4 (3) For uncontrolled blowdown systems reporting under § 98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown systems. (4) For uncontrolled blowdown systems reporting under § 98.253(j), the relevant information required under paragraph (l)(5) of this section. (n) For equipment leaks, the owner or operator shall report: (1) The cumulative CH 4 (2) The method used to calculate the reported equipment leak emissions. (3) The number of each type of emission source listed in Equation Y-21 of this subpart at the facility. (o) For storage tanks, the owner or operator shall report: (1) The cumulative annual CH 4 4 (2) For storage tanks other than those processing unstabilized crude oil: (i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude ( i.e., (ii) [Reserved] (3) The cumulative CH 4 4 (4) For storage tanks that process unstabilized crude oil: (i) The method used to calculate the reported unstabilized crude oil storage tank emissions. (ii)-(iv) [Reserved] (v) The basis for the mole fraction of CH 4 (vi) If you did not use Equation Y-23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH 4 (5)-(7) [Reserved] (p) For loading operations, the owner or operator shall report: (1) The cumulative annual CH 4 (2) The types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, etc.) in which each type of material is loaded. (3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.). (q) Name of each method listed in § 98.254 or a description of manufacturer's recommended method used to determine a measured parameter. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79164, Dec. 17, 2010; 78 FR 71963, Nov. 29, 2013; 79 FR 63795, Oct. 24, 2014; 81 FR 89263, Dec. 9, 2016; 89 FR 31931, Apr. 25, 2024] § 98.257 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section. (a) The records of all parameters monitored under § 98.255. If you comply with the combustion methodology in § 98.252(a), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in § 98.37 and you must keep records of the annual average flow calculations. (b) Verification software records. (1) Volume of flare gas combusted during measurement period (scf) (Equation Y-1b of § 98.253). (2) Mole percent CO 2 (3) Mole percent concentration of compound “x” in the flare gas stream during the measurement period (mole percent) (Equation Y-1b). (4) Carbon mole number of compound “x” in the flare gas stream during the measurement period (mole carbon atoms per mole compound) (Equation Y-1b). (5) Molar volume conversion factor (scf per kg-mole) (Equation Y-1b). (6) Annual volume of flare gas combusted for each flare during normal operations from company records (million (MM) standard cubic feet per year, MMscf/year) (Equation Y-3 of § 98.253). (7) Higher heating value for fuel gas or flare gas for each flare from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y-3). (8) Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations (scf) (Equation Y-3). (9) Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/kg-mole) (Equation Y-3). (10) Molar volume conversion factor (scf per kg-mole) (Equation Y-3). (11) Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas) (Equation Y-3). (12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas) (Equation Y-4 of § 98.253). (13) Annual throughput of unit from company records for each catalytic cracking unit or fluid coking unit (barrels/year) (Equation Y-8 of § 98.253). (14) Coke burn-off factor from engineering calculations (default for catalytic cracking units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y-8). (15) Carbon content of coke based on measurement or engineering estimate (kg C per kg coke) (Equation Y-8). (16) Value of unit-specific CH 4 (17) Annual activity data ( e.g. (18) Value of unit-specific N 2 (19) Annual activity data ( e.g. (20) Carbon content of coke based on measurement or engineering estimate (default = 0.94) (kg C per kg coke) (Equation Y-11 of § 98.253). (21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site for sulfur recovery in the year (scf/year) (Equation Y-12 of § 98.253). (22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kg-mole C/kg-mole gas) (Equation Y-12). (23) Molar volume conversion factor for sour gas sent off site (scf per kg-mole) (Equation Y-12). (24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite sulfur recovery plant (scf/year) (Equation Y-12). (25) Mole fraction of carbon in the sour gas fed to the onsite sulfur recovery plant (kg-mole C/kg-mole gas) (Equation Y-12). (26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg-mole) (Equation Y-12). (27)-(31) [Reserved] (32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-14 of § 98.253). (33) Emission factor for CO 2 2 (34) Emission factor for CH 4 4 (35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y-16a of § 98.253). (36) Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown) (Equation Y-16a). (37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-16b of § 98.253). (38) Emission factor for CO 2 2 (39) Carbon emission factor from asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y-16b). (40) Emission factor for CH 4 4 (41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) from company records or calculated using Equation Y-18a of this subpart (Equations Y-18a, Y-18b and Y-18e in § 98.253) for each delayed coking unit. (42) Internal height of delayed coking unit vessel (feet) (Equation Y-18a in § 98.253) for each delayed coking unit. (43) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed ( i.e., (44) Diameter of delayed coking unit vessel (feet) (Equations Y-18a and Y-18b in § 98.253) for each delayed coking unit. (45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting or draining (metric ton/cycle) (equations Y-18b and Y-18e to § 98.253) for each delayed coking unit. (46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates (equation Y-18b to § 98.253) for each delayed coking unit. (47) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equations Y-18e and Y-18f in § 98.253) for each delayed coking unit. (48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere ( °F) (Equations Y-18c, Y-18d, and Y-18e in § 98.253) for each delayed coking unit. (49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y-18c in § 98.253) for each delayed coking unit. (50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y-18d in § 98.253) for each delayed coking unit. (51) Methane emission factor for delayed coking unit (kilograms CH 4 4 (52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y-18f in § 98.253) for each delayed coking unit. (53) Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining (equation Y-18b to § 98.253) for each delayed coking unit. (54)-(56) [Reserved] (57) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-20 of § 98.253). (58) Molar volume conversion factor (scf per kg-mole) (Equation Y-20). (59) Methane emission factor for uncontrolled blown systems (scf CH 4 (60) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-22 of § 98.253). (61) Quantity of unstabilized crude oil received at the facility (MMbbl/year) (Equation Y-23 of § 98.253). (62) Pressure differential from the previous storage pressure to atmospheric pressure (psi) (Equation Y-23). (63) Average mole fraction of CH 4 4 (64) Molar volume conversion factor (scf per kg-mole) (Equation Y-23). (65) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each vessel (methods specified in § 98.253(n)). (66) Saturation factor specified in § 98.253(n), for each liquid loaded to each vessel (methods specified in § 98.253(n)). (67) True vapor pressure of liquid loaded, for each liquid loaded to each vessel (psia) (methods specified in § 98.253(n)). (68) Molecular weight of vapors (lb per lb-mole), for each liquid loaded to each vessel (methods specified in § 98.253(n)). (69) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees Rankine) (methods specified in § 98.253(n)). (70) Total loading loss (without efficiency correction), for each liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods specified in § 98.253(n)). (71) Overall emission control system reduction efficiency, including the vapor collection system efficiency and the vapor recovery or destruction efficiency (enter zero if no emission controls), for each liquid loaded to each vessel (percent) (methods specified § 98.253(n)). (72) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to each vessel (percent by volume) (methods specified in § 98.253(n)). (73) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon per year) (methods specified in § 98.253(n)). [79 FR 63796, Oct. 24, 2014, as amended at 81 FR 89263, Dec. 9, 2016; 89 FR 31931, Apr. 25, 2024] § 98.258 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart Z—Phosphoric Acid Production § 98.260 Definition of the source category. The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply source with acid. § 98.261 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.262 GHGs to report. (a) You must report CO 2 (b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 § 98.263 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) Calculate and report under this subpart the process CO 2 (b) Calculate and report under this subpart the process CO 2 (1) Calculate the annual CO 2 (i) If your process measurement provides the inorganic carbon content of phosphate rock as an output, calculate and report the process CO 2 where: E m 2 IC n,i P n,i z = Number of months during which the process line m operates. b = Number of different types of phosphate rock in month, by origin. If the grab sample is a composite sample of rock from more than one origin, b = 1. 2000/2205 = Conversion factor to convert tons to metric tons. 44/12 = Ratio of molecular weights, CO 2 (ii) If your process measurement provides the CO 2 2 where: E m 2 CO 2n,i P n,i z = Number of months during which the process line m operates. b = Number of different types of phosphate rock in month, by origin. If the grab sample is a composite sample of rock from more than one origin, b = 1. 2000/2205 = Conversion factor to convert tons to metric tons. (2) You must determine the total emissions from the facility using Equation Z-2 of this section: Where: CO 2 2 E m 2 p = Number of wet-process phosphoric acid process lines. (c) If GHG emissions from a wet-process phosphoric acid process line are vented through the same stack as any combustion unit or process equipment that reports CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 78 FR 71964, Nov. 29, 2013] § 98.264 Monitoring and QA/QC requirements. (a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample. (b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC. (c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes (such as sales records) or you can use data from existing monitoring equipment that is used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66468, Oct. 28, 2010; 78 FR 71964, Nov. 29, 2013] § 98.265 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of the inorganic carbon content or CO 2 2 2 2 (b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best available estimate based on all available process data or data used for accounting purposes. [78 FR 71964, Nov. 29, 2013] § 98.266 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (f) of this section. (a) Annual phosphoric acid production, by origin of the phosphate rock (tons). (b) Annual phosphoric acid production capacity (tons). (c) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate rock from monthly records (percent by weight, expressed as a decimal fraction). (d) Annual phosphate rock consumption from monthly measurement records by origin (tons). (e) If you use a CEMS to measure CO 2 (1) The identification number of each wet-process phosphoric acid process line. (2) The annual CO 2 (f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (9) of this section. (1) Identification number of each wet-process phosphoric acid process line. (2) Annual CO 2 (3) Annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line. (4) Method used to estimate any missing values of inorganic carbon content or carbon dioxide content of phosphate rock for each wet-process phosphoric acid process line. (5) [Reserved] (6) [Reserved] (7) Number of wet-process phosphoric acid process lines. (8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO 2 (9) Annual process CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 78 FR 71964, Nov. 29, 2013; 79 FR 63797, Oct. 24, 2014; 81 FR 89263, Dec. 9, 2016] § 98.267 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each wet-process phosphoric acid production facility. (a) Monthly mass of phosphate rock consumed by origin (tons). (b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine). (c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin. (d) Verification software records. (1) Inorganic carbon content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation Z-1a of § 98.263). (2) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1a). (3) Carbon dioxide content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction) (Equation Z-1b of § 98.263). (4) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1b). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63797, Oct. 24, 2014] § 98.268 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71965, Nov. 29, 2013] Table Z-1 to Subpart Z of Part 98—Default Chemical Composition of Phosphate Rock by Origin Origin Total carbon Central Florida 1.6 North Florida 1.76 North Carolina (Calcined) 0.76 Idaho (Calcined) 0.60 Morocco 1.56 Subpart AA—Pulp and Paper Manufacturing § 98.270 Definition of source category. (a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes. (b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section: (1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process). (2) Chemical recovery combustion units at sulfite facilities. (3) Chemical recovery combustion units at stand-alone semichemical facilities. (4) Pulp mill lime kilns at kraft and soda facilities. (5) Systems for adding makeup chemicals (CaCO 3 2 3 § 98.271 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.272 GHGs to report. You must report the emissions listed in paragraphs (a) through (f) of this section: (a) CO 2 2 4 2 (b) CO 2 2 4 2 (c) CO 2 2 4 2 (d) CO 2 2 4 2 (e) CO 2 3 2 3 (f) CO 2 4 2 § 98.273 Calculating GHG emissions. (a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO 2 2 4 2 (1) Calculate CO 2 2 (2) Calculate CH 4 2 2 (3) Calculate biogenic CO 2 4 2 Where: CO 2 4 2 2 4 2 Solids = Mass of spent liquor solids combusted (short tons per year) determined according to § 98.274(b). HHV = Annual high heat value of the spent liquor solids (mmBtu per kilogram) determined according to § 98.274(b). EF = Default emission factor for CO 2 4 2 2 4 2 0.90718 = Conversion factor from short tons to metric tons. (4) Calculate biogenic CO 2 (b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine CO 2 4 2 (1) Calculate CO 2 2 (2) Calculate CH 4 2 2 (3) Calculate biogenic CO 2 Where: Biogenic CO 2 2 Solids = Mass of the spent liquor solids combusted (short tons per year) determined according to § 98.274(b). CC = Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction, e.g. 44/12 = Ratio of molecular weights, CO 2 0.90718 = Conversion from short tons to metric tons. (4) Calculate biogenic CO 2 (c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO 2 4 2 (1) Calculate CO 2 2 (2) Calculate CH 4 2 2 4 2 (3) Biogenic CO 2 3 2 (4) Calculate biogenic CO 2 (d) For makeup chemical use, you must calculate CO 2 2 Where: CO 2 2 M (CaCO 3 3 M (NaCO 3 2 3 44 = Molecular weight of CO 2 100 = Molecular weight of CaCO 3 105.99 = Molecular weight of Na 2 3 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79166, Dec. 17, 2010; 78 FR 71965, Nov. 29, 2013; 81 FR 89264, Dec. 9, 2016; 89 FR 31931, Apr. 25, 2024] § 98.274 Monitoring and QA/QC requirements. (a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request. (b) Fuel properties needed to perform the calculations in Equations AA-1 and AA-2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section. (1) High heat values of black liquor must be determined no less than annually using T684 om-06 Gross Heating Value of Black Liquor, TAPPI (incorporated by reference, see (2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section. (i) Measure the mass of spent liquor solids annually (or more frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference in § 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year. (ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit. (3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see (c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented. (d) Records must be made available upon request for verification of the calculations and measurements. § 98.275 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section: (a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual measurements are determined to be invalid. (b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Alternatively, records of the daily spent liquor solids firing rate obtained to comply with § 63.866(c)(1) of this chapter may be used, adjusting for the duration of the missing measurements, as appropriate. (c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates. [74 FR 56374, Oct. 30, 2009, as amended at 81 FR 89264, Dec. 9, 2016] § 98.276 Data reporting requirements. In addition to the information required by § 98.3(c) and the applicable information required by § 98.36, each annual report must contain the information in paragraphs (a) through (l) of this section as applicable: (a) Annual emissions of CO 2 2 4 2 (b) [Reserved] (c) Basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see (d) [Reserved] (e) The default emission factor for CO 2 4 2 2 4 2 (f)-(i) [Reserved] (j) Annual steam purchases (pounds of steam per year). (k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total. (l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and (2) of this section. (1) The quantity of calcium oxide (CaO) produced (metric tons). (2) The percent of annual heat input, individually for each fossil fuel type. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79166, Dec. 17, 2010; 78 FR 71965, Nov. 29, 2013; 79 FR 63797, Oct. 24, 2014; 89 FR 31932, Apr. 25, 2024] § 98.277 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (g) of this section. (a) GHG emission estimates (including separate estimates of biogenic CO 2 (b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities. (c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility. (d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for determining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system). If an online measurement system is used, you must retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements. (e) Annual steam purchases. (f) Annual quantities of makeup chemicals used. (g) Verification software records. (1) Mass of the solid fuel combusted (tons/year) (Equation C-1 of § 98.33). (2) Volume of the liquid fuel combusted (gallons/year) (Equation C-1). (3) Volume of the gaseous fuel combusted (scf/year) (Equation C-1). (4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33). (5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33). (6) Mass of the solid fuel combusted (tons/year) (Equation C-2a of § 98.33). (7) Volume of the liquid fuel combusted (gallons/year) (Equation C-2a). (8) Volume of the gaseous fuel combusted (scf/year) (Equation C-2a). (9) Annual mass of the solid fuel combusted (short tons/year) (Equation C-3 of § 98.33). (10) Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3). (11) Annual volume of the liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33). (12) Annual average carbon content of the liquid fuel (kg C per gallon of fuel) (Equation C-4). (13) Annual volume of the gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33). (14) Annual average carbon content of the gaseous fuel (kg C per kg of fuel) (Equation C-5). (15) Annual average molecular weight of the gaseous fuel (kg/kg-mole) (Equation C-5). (16) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5). (17) Identify if you will use the default high heat value from Table C-1 of subpart C of this part, or actual HHV data (Equation C-8 of § 98.33). (18) High heat value of the fuel (mmBTU/tons) (Equation C-8). (19) High heat value of the fuel (mmBTU/gallons) (Equation C-8). (20) High heat value of the fuel (mmBTU/scf) (Equation C-8). (21) Mass of spent liquor solids combusted from each chemical recovery furnace located at a kraft or soda facility, in short tons in year, determined according to § 98.274(b) (tons/year) (Equation AA-1 of § 98.273). (22) Annual high heat value of the spent liquor solids from each chemical recovery furnace located at a kraft or soda facility determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1). (23) Annual high heat value of the spent liquor solids from each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1). (24) Mass of the spent liquor solids combusted in short tons per year determined according to § 98.274(b) (tons/year) (Equation AA-2 of § 98.273). (25) Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction (e.g., 95% = 0.95)) (Equation AA-2). (26) Make-up quantity of CaCO 3 (27) Make-up quantity of Na 2 3 [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014; 89 FR 31932, Apr. 25, 2024] § 98.278 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table AA-1 to Subpart AA of Part 98—Kraft Pulping Liquor Emissions Factors for Biomass-Based CO 2 4 2 Wood furnish Biomass-based emissions factors a 2 CH 4 N 2 North American Softwood 94.4 0.0019 0.00042 North American Hardwood 93.7 0.0019 0.00042 Bagasse 95.5 0.0019 0.00042 Bamboo 93.7 0.0019 0.00042 Straw 95.1 0.0019 0.00042 a [78 FR 71965, Nov. 29, 2013] Table AA-2 to Subpart AA of Part 98—Kraft Lime Kiln and Calciner Emissions Factors for CH 4 2 Fuel Fossil fuel-based emissions factors (kg/mmBtu HHV) Kraft rotary lime kilns Kraft calciners a CH 4 N 2 CH 4 N 2 Residual Oil (any type) 0.0027 0 0.0027 0.0003 Distillate Oil (any type) 0.0027 0 0.0027 0.0004 Natural Gas 0.0027 0 0.0027 0.0001 Biogas 0.0027 0 0.0027 0.0001 Petroleum coke 0.0027 0 b b Other Fuels See Table C-2 0 See Table C-2 See Table C-2 a b [78 FR 71965, Nov. 29, 2013, as amended at 81 FR 89264, Dec. 9, 2016] Subpart BB—Silicon Carbide Production § 98.280 Definition of the source category. Silicon carbide production includes any process that produces silicon carbide for abrasive purposes. § 98.281 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.282 GHGs to report. You must report: (a) CO 2 (b) CO 2 4 2 [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013] § 98.283 Calculating GHG emissions. You must calculate and report the combined annual process CO 2 (a) Calculate and report under this subpart the combined annual process CO 2 (b) Calculate and report under this subpart the combined annual process CO 2 (1) Use Equation BB-1 of this section to calculate the facility-specific emissions factor for determining CO 2 2 Where: EF CO2,n 2 2 0.65 = Adjustment factor for the amount of carbon in silicon carbide product (assuming 35 percent of carbon input is in the carbide product). CCF n 44/12 = Ratio of molecular weights, CO 2 (2) Calculate annual CO 2 Where: CO 2 2 2 T n EF CO2,n 2 2000/2205 = Conversion factor to convert tons to metric tons. n = Number of month. (c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013] § 98.284 Monitoring and QA/QC requirements. (a) You must measure your consumption of petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records. (b) You must document the procedures used to ensure the accuracy of monthly petroleum coke consumption measurements. (c) For CO 2 see see (d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.285 Procedures for estimating missing data. For the petroleum coke input procedure in § 98.283(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, 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 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 value of the monthly carbon content of petroleum coke, the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period. (b) For each missing value of the monthly petroleum coke consumption, the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records). § 98.286 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraph (a) or (b) of this section, and paragraph (c) of this section, as applicable for each silicon carbide production facility. (a) If a CEMS is used to measure process CO 2 (1) Annual consumption of petroleum coke (tons). (2) Annual production of silicon carbide (tons). (3) Annual production capacity of silicon carbide (tons). (b) If a CEMS is not used to measure process CO 2 (1) [Reserved] (2) Annual production of (3) Annual production capacity of silicon carbide (tons). (4) [Reserved] (5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method. (6) [Reserved] (7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a decimal fraction). (8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months). (c) If methane abatement technology is used at the silicon carbide production facility, you must report the information in paragraphs (c)(1) through (3) of this section. Upon reporting this information once in an annual report, you are not required to report this information again unless the information changes during a reporting year, in which case, the reporter must include any updates in the annual report for the reporting year in which the change occurred. (1) Type of methane abatement technology used on each silicon carbide process unit or production furnace, and date of installation for each. (2) Methane destruction efficiency for each methane abatement technology (percent destruction). You must either use the manufacturer's specified destruction efficiency or the destruction efficiency determined via a performance test. If you report the destruction efficiency determined via a performance test, you must also report the test method that was used during the performance test. (3) Percentage of annual operating hours that methane abatement technology was in use for all silicon carbide process units or production furnaces combined. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013; 79 FR 63798, Oct. 24, 2014; 89 FR 31932, Apr. 25, 2024] § 98.287 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each silicon carbide production facility. (a) If a CEMS is used to measure CO 2 (1) Records of all petroleum coke purchases. (2) Annual operating hours. (b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b): (1) Records of all analyses and calculations conducted for reported data listed in § 98.286(b). (2) Records of all petroleum coke purchases. (3) Annual operating hours. (c) Verification software records. (1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method (percent by weight expressed as a decimal fraction) (Equation BB-1 of § 98.283). (2) Petroleum coke consumption in month (tons) (Equation BB-2 of § 98.283). (d) Records of all information reported as required under § 98.286(c). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014; 89 FR 31933, Apr. 25, 2024] § 98.288 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart CC—Soda Ash Manufacturing § 98.290 Definition of the source category. (a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a)(1) through (3) of this section: (1) Calcining trona. (2) Calcining sodium sesquicarbonate. (3) Using a liquid alkaline feedstock process that directly produces CO 2 (b) In the context of the soda ash manufacturing sector, “calcining” means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate. § 98.291 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.292 GHGs to report. You must report: (a) CO 2 (b) CO 2 (c) CH 4 2 (d) CO 2 4 2 § 98.293 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) For each soda ash manufacturing line that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO 2 2 (b) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process CO 2 2 (1) Calculate and report under this subpart the combined process and combustion CO 2 2 (2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO 2 Where: E k 2 (IC T n (IC sa n (T t n (T sa n 2000/2205 = Conversion factor to convert tons to metric tons. 0.097/1 = Ratio of ton of CO 2 0.138/1 = Ratio of ton of CO 2 (3) Site-specific emission factor method. 2 2 2 (i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour. (ii) Using the test data, you must calculate the hourly CO 2 Where: ER CO2 2 C CO2 2 2 10000 = Parts per million per percent 2.59 × 10 −9 44 = Pounds per pound-mole of carbon dioxide. Q = Stack gas volumetric flow rate per minute (dscfm). 60 = Minutes per hour 4.53 × 10 −4 (iii) Using the test data, you must calculate a CO 2 Where: EF CO2 2 2 ER CO2 2 V t 4.53 × 10 −4 (iv) You must calculate annual CO 2 Where: E k 2 EF CO2 2 2 V a H = Annual operating hours for the each manufacturing line. 0.453 = Conversion factor (metric tons/thousand pounds). (4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO 2 4 2 § 98.294 Monitoring and QA/QC requirements. Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section should be used for the procedure chosen. (a) If you determine your emissions using § 98.293(b)(2) (Equation CC-1 of this subpart) you must: (1) Determine the monthly inorganic carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). ASTM E359-00(Reapproved 2005) e1 is designed to measure the total alkalinity in soda ash not in trona. The modified method referred to above adjusts the regular ASTM method to express the results in terms of trona. Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination. (2) Measure the mass of trona input to each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes. (3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed. (b) If you calculate CO 2 (1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination. (2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes. (3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced. (c) If you calculate CO 2 (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) Sample the stack gas and conduct three emissions test runs of 1 hour each. (3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO 2 (i) Analysis of samples, determination of emissions, and raw data. (ii) All information and data used to derive the emissions factor(s). (iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each test and document how it was determined. (4) You must also determine the annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 81 FR 89264, Dec. 9, 2016] § 98.295 Procedures for estimating missing data. For the emission calculation methodologies in § 98.293(b)(2) and (b)(3), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., inorganic carbon content values, 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 the paragraphs (a) through (d) of this section. You must document and keep records of the procedures used for all such missing value estimates. (a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following the missing data incident. If no quality-assured data on inorganic carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period. (b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes. (c) For each missing value collected during the performance test (hourly CO 2 (d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the meter can measure. § 98.296 Data reporting requirements. 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 appropriate for each soda ash manufacturing facility. (a) If a CEMS is used to measure CO 2 (1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (tons). (2) Annual production of soda ash for each manufacturing line (tons). (3) Annual production capacity of soda ash for each manufacturing line (tons). (4) Identification number of each manufacturing line. (b) If a CEMS is not used to measure CO 2 (1) Identification number of each manufacturing line. (2) Annual process CO 2 (3) Annual production of soda ash for each manufacturing line (tons). (4) Annual production capacity of soda ash for each manufacturing line (tons). (5)-(7) [Reserved] (8) Whether CO 2 (9) Number of manufacturing lines located used to produce soda ash. (10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§ 98.293(b)(3)) to estimate emissions then you must report the following relevant information for each manufacturing line or stack: (i) Stack gas volumetric flow rate during performance test (dscfm). (ii) Hourly CO 2 2 (iii) CO 2 2 (iv) CO 2 (v) Average process vent flow from mine water stripper/evaporator during performance test (pounds/hour). (vi) Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour). (11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11): (i) Trona or soda ash (number of months). (ii) Inorganic carbon contents of trona or soda ash (weeks). (iii) Process vent flow rate from mine water stripper/evaporator (number of months). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 79 FR 63798, Oct. 24, 2014] § 98.297 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each soda ash manufacturing line. (a) If a CEMS is used to measure CO 2 (1) Monthly production of soda ash (tons) (2) Monthly consumption of trona or liquid alkaline feedstock (tons) (3) Annual operating hours (hours). (b) If a CEMS is not used to measure emissions, then you must retain records for the information listed in this paragraph (b): (1) Records of all analyses and calculations conducted for determining all reported data as listed in § 98.296(b). (2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in § 98.294(b) (percent by weight expressed as a decimal fraction). (3) Annual operating hours for each manufacturing line used to produce soda ash (hours). (4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash production measurements 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. (5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method to estimate emissions (§ 98.293(b)(3)) then you must also retain the following relevant information: (i) Records of performance test results. (ii) You must document the procedures used to ensure the accuracy of the annual average vent flow measurements including, but not limited to, calibration of flow rate 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. (c) Verification software records. (1) Inorganic carbon content in trona input, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-1 of § 98.293). (2) Mass of trona input in month (tons) (Equation CC-1). (3) Inorganic carbon content in soda ash output, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-2 of § 98.293). (4) Mass of soda ash output in month (tons) (Equation CC-2). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63798, Oct. 24, 2014] § 98.298 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart DD—Electrical Transmission and Distribution Equipment Use Source: 75 FR 74855, Dec. 1, 2010, as amended at 89 FR 31933, Apr. 25, 2024, unless otherwise noted. § 98.300 Definition of the source category. (a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing fluorinated GHGs, including but not limited to sulfur hexafluoride (SF 6 (1) Gas-insulated substations. (2) Circuit breakers. (3) Switchgear, including closed-pressure and hermetically sealed-pressure switchgear and gas-insulated lines containing fluorinated GHGs, including but not limited to SF 6 (4) Gas containers such as pressurized cylinders. (5) Gas carts. (6) Electric power transformers. (7) Other containers of fluorinated GHG, including but not limited to SF 6 (b) [Reserved] § 98.301 Reporting threshold. (a) You must report GHG emissions under this subpart if you are an electric power system as defined in § 98.308 and your facility meets the requirements of § 98.2(a)(1). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO 2 Where: E = Annual emissions for threshold applicability purposes (metric tons CO 2 NC EPS,j GHG i,w EPS,j GWP i EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1. i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 0.000453592 = Conversion factor from lbs to metric tons. (b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in table A-3 or A-4 to subpart A of this part is not required to report emissions under subpart DD of this part unless the total estimated emissions of fluorinated GHGs that are components of reportable insulating gases, as calculated in equation DD-2 to this section, equals or exceeds 25,000 tons CO 2 Where: E = Annual emissions for threshold applicability purposes (metric tons CO 2 NC other,j GHG i,w other,j GWP i EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1. i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 0.000453592 = Conversion factor from lbs to metric tons. § 98.302 GHGs to report. You must report emissions of each fluorinated GHG, including but not limited to SF 6 Where: GWP j GHG i,w GWP i i = GHG contained in the electrical transmission and distribution equipment. § 98.303 Calculating GHG emissions. (a) Calculating GHG emissions. Where: User Emissions i GHG i,w Decrease in Inventory of Reportable Insulating Gas j = (Pounds of reportable insulating gas j stored in containers, but not in energized equipment, at the beginning of the year)−(Pounds of reportable insulating gas j stored in containers, but not in energized equipment, at the end of the year). Reportable insulating gas inside equipment that is not energized is considered to be “stored in containers.” Acquisitions of Reportable Insulating gas j = (Pounds of reportable insulating gas j purchased or otherwise acquired from chemical producers, chemical distributors, or other entities in bulk) + (Pounds of reportable insulating gas j purchased or otherwise acquired from equipment manufacturers, equipment distributors, or other entities with or inside equipment, including hermetically sealed-pressure switchgear, while the equipment was not in use) + (Pounds of each SF 6 e.g., Disbursements of Reportable Insulating gas j = (Pounds of reportable insulating gas j returned to suppliers) + (Pounds of reportable insulating gas j sent off site for recycling) + (Pounds of reportable insulating gas j sent off-site for destruction) + (Pounds of reportable insulating gas j that was sold or transferred to other entities in bulk) + (Pounds of reportable insulating gas j contained in equipment, including hermetically sealed-pressure switchgear, that was sold or transferred to other entities while the equipment was not in use) + (Pounds of reportable insulating gas j inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., Net Increase in Total Nameplate Capacity of Equipment Operated containing reportable insulating gas j = (The Nameplate Capacity of new equipment, as defined at § 98.308, containing reportable insulating gas j in pounds)−(Nameplate Capacity of retiring equipment, as defined at § 98.308, containing reportable insulating gas j in pounds). (Note that Nameplate Capacity refers to the full and proper charge of equipment rather than to the actual charge, which may reflect leakage). (b) Nameplate capacity adjustments. (1) If you elect to measure the nameplate capacity value(s) of one or more pieces of electrical equipment with a voltage capacity greater than 38 kV, you must measure the nameplate capacity values of all the electrical equipment in your facility that has a voltage capacity greater than 38 kV and that is installed or retired in that reporting year and in subsequent reporting years. (2) You must adopt the measured nameplate capacity value for any piece of equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer equals or exceeds two percent of the nameplate capacity value most recently specified by the manufacturer. (3) You may adopt the measured nameplate capacity value for equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer, but if you elect to adopt the measured nameplate capacity for that equipment, then you must adopt the measured nameplate capacity value for all of the equipment for which the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer. This applies in the reporting year in which you first adopt the measured nameplate capacity for the equipment and in subsequent reporting years. (4) Users of electrical equipment measuring the nameplate capacity of any new electrical equipment must: (i) Record the amount of insulating gas in the equipment at the time the equipment was acquired (pounds), either per information provided by the manufacturer, or by transferring insulating gas from the equipment to a gas container and measuring the amount of insulating gas transferred. The equipment user is responsible for ensuring the gas is accounted for consistent with the methodologies specified in paragraphs (b)(4)(ii) through (iii) and (b)(5) of this section. If no insulating gas was in the device when it was acquired, record this value as zero. (ii) If insulating gas is added to the equipment subsequent to the acquisition of the equipment to energize it the first time, transfer the insulating gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. Follow the manufacturer-specified procedure to ensure that the measured temperature accurately reflects the temperature of the insulating gas, e.g., (A) To determine the amount of reportable insulating gas transferred to the electrical equipment, weigh the gas container being used to fill the device prior to, and after, the addition of the reportable insulating gas to the electrical equipment, and subtract the second value (after-transfer gas container weight) from the first value (prior-to-transfer gas container weight). Account for any gas contained in hoses before and after the transfer. (B) Connect a mass flow meter between the electrical equipment and a gas cart. Transfer gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. During gas transfer, you must keep the mass flow rate within the range specified by the mass flow meter manufacturer to assure an accurate and precise mass flow meter reading. Close the connection to the GIE from the mass flow meter hose and ensure that the gas trapped in the filling hose returns through the mass flow meter. Calculate the amount of gas transferred from the mass reading on the mass flow meter. (iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain the measured nameplate capacity for the new equipment. (5) Electrical equipment users measuring the nameplate capacity of any retiring electrical equipment must: (i) Measure and record the initial system pressure and vessel temperature prior to removing any insulating gas. (ii) Compare the initial system pressure and temperature to the equipment manufacturer's temperature/pressure curve for that equipment and insulating gas. (iii) If the temperature-compensated initial system pressure of the electrical equipment does not match the temperature-compensated design operating pressure specified by the equipment manufacturer, you may either: (A) Add or remove insulating gas to/from the electrical equipment until the manufacturer-specified value is reached, or (B) If the temperature-compensated initial system pressure of the electrical equipment is no higher than the temperature-compensated design operating pressure specified by the manufacturer and no lower than five pounds per square inch (5 psi) less than the temperature-compensated design operating pressure specified by the manufacturer, use equation DD-5 to this section to calculate the nameplate capacity based on the mass recorded under paragraph (b)(5)(vi) of this section. (iv) Weigh the gas container being used to receive the gas and record this value. (v) Recover insulating gas from the electrical equipment until five minutes after the pressure in the electrical equipment reaches a pressure of at most five pounds per square inch absolute (5 psia). (vi) Record the amount of insulating gas recovered (pounds) by weighing the gas container that received the gas and subtracting the weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section from this value. Account for any gas contained in hoses before and after the transfer. The amount of gas recovered shall be the measured nameplate capacity for the electrical equipment unless the final temperature-compensated pressure of the electrical equipment exceeds 0.068 psia (3.5 Torr) or the electrical equipment user is calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, in which cases the measured nameplate capacity shall be the result of equation DD-5 to this section. (vii) If you are calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, use equation DD-5 to this section to do so. Where: NC C P i P f P NC i.e., M R (viii) Record the final system pressure and vessel temperature. (6) Instead of measuring the nameplate capacity of electrical equipment when it is retired, users may measure the nameplate capacity of electrical equipment during maintenance activities that require opening the gas compartment, but they must follow the procedures set forth in paragraph (b)(5) of this section. (7) If the electrical equipment will remain energized, and the electrical equipment user is adopting the user-measured nameplate capacity, the electrical equipment user must affix a revised nameplate capacity label, showing the revised nameplate value and the year the nameplate capacity adjustment process was performed, to the device by the end of the calendar year in which the process was completed. The manufacturer's previous nameplate capacity label must remain visible after the revised nameplate capacity label is affixed to the device. (8) For each piece of electrical equipment whose nameplate capacity was adjusted during the reporting year, the revised nameplate capacity value must be used in all provisions wherein the nameplate capacity is required to be recorded, reported, or used in a calculation in this subpart unless otherwise specified herein. (9) The nameplate capacity of a piece of electrical equipment may only be adjusted more than once if the physical capacity of the device has changed ( e.g., (10) Measuring devices used to measure the nameplate capacity of electrical equipment under this paragraph (b) must meet the following accuracy and precision requirements: (i) Flow meters must be certified by the manufacturer to be accurate and precise to within one percent of the largest value that the flow meter can, according to the manufacturer's specifications, accurately record. (ii) Pressure gauges must be certified by the manufacturer to be accurate and precise to within 0.5% of the largest value that the gauge can, according to the manufacturer's specifications, accurately record. (iii) Temperature gauges must be certified by the manufacturer to be accurate and precise to within ±1.0 °F. (iv) Scales must be certified by the manufacturer to be accurate and precise to within one percent of the true weight. § 98.304 Monitoring and QA/QC requirements. (a) [Reserved] (b) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting: (1) Review inputs to equation DD-4 to § 98.303 to ensure inputs and outputs to the company's system are included. (2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in fluorinated GHG Inventory and the Net Increase in Total Nameplate Capacity may be calculated as negative numbers. (3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year. (4) Ensure that in addition to fluorinated GHG purchased from bulk gas distributors, fluorinated GHG purchased from Original Equipment Manufacturers (OEM) and fluorinated GHG returned to the facility from off-site recycling are also accounted for among the total additions. (c) Ensure the following QA/QC methods are employed throughout the year: (1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ±2 pounds, of residual gas amounts in the cylinders returned to the gas supplier. (2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer's specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer. (3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system). (d) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013] § 98.305 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for fluorinated GHGs, and from similar equipment repair, replacement, and maintenance operations. § 98.306 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical: (a) Nameplate capacity of equipment (pounds) containing each insulating gas: (1) Existing at the beginning of the year (excluding hermetically sealed-pressure switchgear). (2) New hermetically sealed-pressure switchgear during the year. (3) New equipment other than hermetically sealed-pressure switchgear during the year. (4) Retired hermetically sealed-pressure switchgear during the year. (5) Retired equipment other than hermetically sealed-pressure switchgear during the year. (b) Transmission miles (length of lines carrying voltages above 35 kilovolts). (c) Distribution miles (length of lines carrying voltages at or below 35 kilovolts). (d) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the beginning of the year. (e) Pounds of each reportable insulating gas stored in containers, but not in energized equipment, at the end of the year. (f) Pounds of each reportable insulating gas purchased or otherwise acquired in bulk from chemical producers, chemical distributors, or other entities. (g) Pounds of each reportable insulating gas purchased or otherwise acquired from equipment manufacturers, equipment distributors, or other entities with or inside equipment, including hermetically sealed-pressure switchgear, while the equipment was not in use. (h) Pounds of each reportable insulating gas returned to facility after off-site recycling. (i) Pounds of each reportable insulating gas acquired inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., (j) Pounds of each reportable insulating gas returned to suppliers. (k) Pounds of each reportable insulating gas that was sold or transferred to other entities in bulk. (l) Pounds of each reportable insulating gas sent off-site for recycling. (m) Pounds of each reportable insulating gas sent off-site for destruction. (n) Pounds of each reportable insulating gas contained in equipment, including hermetically sealed-pressure switchgear, that was sold or transferred to other entities while the equipment was not in use. (o) Pounds of each reportable insulating gas disbursed inside equipment, except hermetically sealed-pressure switchgear, that was transferred while the equipment was in use, e.g., (p) State(s) or territory in which the facility lies. (q) The number of reportable-insulating-gas-containing pieces of equipment in each of the following equipment categories: (1) New hermetically sealed-pressure switchgear during the year. (2) New equipment other than hermetically sealed-pressure switchgear during the year. (3) Retired hermetically sealed-pressure switchgear during the year. (4) Retired equipment other than hermetically sealed-pressure switchgear during the year. (r) The total of the nameplate capacity values most recently assigned by the electrical equipment manufacturer(s) to each of the following groups of equipment: (1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year. (2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year. (s) The total of the nameplate capacity values measured by the electrical equipment user for each of the following groups of equipment: (1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year. (2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year. (t) For each reportable insulating gas reported in paragraphs (a), (d) through (o), and (q) of this section, an ID number or other appropriate descriptor that is unique to that reportable insulating gas. (u) For each ID number or descriptor reported in paragraph (t) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas. [74 FR 56374, Oct. 30, 2009, as amended at 81 FR 89264, Dec. 9, 2016] § 98.307 Records that must be retained. (a) In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306. (b) For each piece of electrical equipment whose nameplate capacity is measured by the equipment user, retain records of the following: (1) Equipment manufacturer name. (2) Year equipment was manufactured. If the date year the equipment was manufactured cannot be determined, report a best estimate of the year of manufacture and record how the estimated year was determined. (3) Manufacturer serial number. For any piece of equipment whose serial number is unknown ( e.g., (4) Equipment type ( i.e., (5) Equipment voltage capacity (in kilovolts). (6) The name and GWP of each insulating gas used. (7) Nameplate capacity value (pounds), as specified by the equipment manufacturer. The value must reflect the latest value specified by the manufacturer during the reporting year. (8) Nameplate capacity value (pounds) measured by the equipment user. (9) The date the nameplate capacity measurement process was completed. (10) The measurements and calculations used to calculate the value in paragraph (b)(8) of this section. (11) The temperature-pressure curve and/or other information used to derive the initial and final temperature-adjusted pressures of the equipment. (12) Whether or not the nameplate capacity value in paragraph (b)(8) of this section has been adopted for the piece of electrical equipment. § 98.308 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Facility, (1) The point(s) at which electric energy is obtained from an electricity generating unit or a different electric power transmission or distribution entity that does not have a common owner; and (2) The point(s) at which any customer or another electric power transmission or distribution entity that does not have a common owner receives the electric energy. The facility also includes servicing inventory for such equipment that contains fluorinated GHGs. Electric power transmission or distribution entity Energized, Insulating gas, 6 New equipment, e.g., Operator, Reportable insulating gas, Retired equipment, e.g., Subpart EE—Titanium Dioxide Production § 98.310 Definition of the source category. The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide. § 98.311 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). § 98.312 GHGs to report. (a) You must report CO 2 (b) You must report CO 2 4 2 § 98.313 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) Calculate and report under this subpart the process CO 2 (b) Calculate and report under this subpart the annual process CO 2 2 2 (1) You must calculate the annual CO 2 Where: CO 2 2 E p 2 p = Process line. m = Number of separate chloride process lines located at the facility. (2) You must calculate the annual CO 2 Where: E p 2 C p,n 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion of tons to metric tons. CCF n n = Number of month. (3) If facility generates carbon-containing waste, you must calculate the total annual quantity of carbon-containing waste produced from all process lines using Equation EE-3 of this section and its carbon contents according to § 98.314(e) and (f): Where: TWC = Annual production of carbon-containing waste from titanium dioxide production facility (tons). WC p,n p = Process line. m = Total number of process lines. n = Number of month. (c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or process equipment that reports CO 2 2 § 98.314 Monitoring and QA/QC requirements. (a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records. (b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption measurements. (c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see see (d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176-89 and ASTM D5373-08. (e) You must determine the quantity of carbon-containing waste generated from each titanium dioxide production line on a monthly basis using plant instruments used for accounting purposes including direct measurement weighing the carbon-containing waste not used during the process (by belt scales or a similar device) or through the use of sales records. (f) You must determine the carbon contents of the carbon-containing waste from each titanium production line on an annual basis by collecting and analyzing a representative sample of the material using ASTM D3176-89 and ASTM D5373-08. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010] § 98.315 Procedures for estimating missing data. For the petroleum coke input procedure in § 98.313(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.). Therefore, whenever the monitoring and quality assurance procedures in § 98.315 cannot be followed, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (c) of this section. You must document and keep records of the procedures used for all such estimates. (a) For each missing value of the monthly carbon content of calcined petroleum coke the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents for the month immediately preceding and the month immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period. (b) For each missing value of the monthly calcined petroleum coke consumption and/or carbon-containing waste, the substitute data value shall be the best available estimate of the monthly petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records). (c) For each missing value of the carbon content of carbon-containing waste, you must conduct a new analysis following the procedures in § 98.314(f). § 98.316 Data reporting requirements. 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 for each titanium dioxide production line. (a) If a CEMS is used to measure CO 2 (1) Identification number of each process line. (2) Annual consumption of calcined petroleum coke (tons). (3) Annual production of titanium dioxide (tons). (4) Annual production capacity of titanium dioxide (tons). (5) Annual production of carbon-containing waste (tons), if applicable. (b) If a CEMS is not used to measure CO 2 (1) Identification number of each process line. (2) Annual CO 2 (3) Annual consumption of calcined petroleum coke for each process line (tons). (4) Annual production of titanium dioxide for each process line (tons). (5) Annual production capacity of titanium dioxide for each process line (tons). (6) [Reserved] (7) Annual production of carbon-containing waste for each process line (tons), if applicable. (8) Monthly production of titanium dioxide for each process line (tons). (9) [Reserved] (10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard methods. (11) Carbon content for carbon-containing waste for each process line (percent by weight expressed as a decimal fraction). (12) If carbon content of petroleum coke is based on self measurement, the ASTM standard methods used. (13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under § 98.314(d) (percent by weight expressed as a decimal fraction). (14) Number of separate chloride process lines located at the facility. (15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66469, Oct. 28, 2010; 79 FR 63799, Oct. 24, 2014] § 98.317 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each titanium dioxide production facility. (a) If a CEMS is used to measure CO 2 (1) Records of all calcined petroleum coke purchases. (2) Annual operating hours for each titanium dioxide process line. (b) If a CEMS is not used to measure CO 2 (1) Records of all calcined petroleum coke purchases (tons). (2) Records of all analyses and calculations conducted for all reported data as listed in § 98.316(b). (3) Sampling analysis results for carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction). (4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable. (5) Monthly production of carbon-containing waste (tons). (6) You must document the procedures used to ensure the accuracy of the monthly petroleum coke consumption and quantity of carbon-containing waste measurement 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. (7) Annual operating hours for each titanium dioxide process line (hours). (c) Verification software records. (1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method incorporated by reference in § 98.7 according to § 98.314(c) (percent by weight, expressed as a decimal fraction) (Equation EE-2 of § 98.313). (2) Calcined petroleum coke consumption for process line in month (tons) (Equation EE-2). [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63799, Oct. 24, 2014] § 98.318 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart FF—Underground Coal Mines Source: 75 FR 39763, July 12, 2010, unless otherwise noted. § 98.320 Definition of the source category. (a) This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems. An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply: (1) Mine development is underway. (2) Coal has been produced within the last 90 days. (3) Mine personnel are present in the mine workings. (4) Mine ventilation fans are operative. (5) The mine is designated as an ”intermittent” mine by the Mine Safety and Health Administration (MSHA). (b) This source category includes the following: (1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsite, or otherwise destroyed (including by ventilation air methane (VAM) oxidizers). (2) Each degasification system well or gob gas vent hole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emitted, and those where the gas is sold, used onsite, or otherwise destroyed (including by flaring). (c) This source category does not include abandoned or closed mines, surface coal mines, or post-coal mining activities ( e.g., [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71966, Nov. 29, 2013] § 98.321 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of § 98.2(a)(1). § 98.322 GHGs to report. (a) You must report CH 4 (b) You must report CH 4 (c) You must report net CH 4 (d) You must report under this subpart the CO 2 4 e.g., (e) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO 2 4 2 4 (f) An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5 of subpart A of this part, or from stationary combustion (subpart C of this part), is not required to report emissions under this subpart unless the coal mine liberates 36,500,000 actual cubic feet (acf) or more of methane per year from its ventilation system. [75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 78 FR 71966, Nov. 29, 2013] § 98.323 Calculating GHG emissions. (a) For each ventilation shaft, vent hole, or centralized point into which CH 4 4 4 Where: CH 4V 4 4 V = Volumetric flow rate for the quarter (acfm) based on sampling or a flow rate meter. If a flow rate meter is used and the meter automatically corrects to standard temperature and pressure, then use scfm and replace “520°R/T × P/1 atm” with “1”. MCF = Moisture correction factor for the measurement period, volumetric basis. = 1 when V and C are measured on a dry basis or if both are measured on a wet basis. = 1-(f H2O = 1/[1-(f H2O (f H2O 4 C = CH 4 n = The number of days in the quarter where active ventilation of mining operations is taking place at the monitoring point. To obtain the number of days in the quarter, divide the total number of hours in the quarter where active ventilation is taking place by 24 hours per day. 0.0423 = Density of CH 4 520 °R = 520 degrees Rankine. T = Temperature at which flow is measured (°R) for the quarter. P = Absolute pressure at which flow is measured (atm) for the quarter. The annual average barometric pressure from the nearest NOAA weather service station may be used as a default. 1,440 = Conversion factor (min/day). 0.454/1,000 = Conversion factor (metric ton/lb). (1) The quarterly periods are: (i) January 1-March 31. (ii) April 1-June 30. (iii) July 1-September 30. (iv) October 1-December 31. (2) Values of V, C, T, P, and, if applicable, (f H2O (3) If a facility has more than one monitoring point, the facility must calculate total CH 4 4VTotal 4 Where: CH 4VTotal 4 4 CH 4V 4 4 m = Number of ventilation monitoring points. (b) For each monitoring point in the degasification system (this could be at each degasification well and/or vent hole, or at more centralized points into which CH 4 4 4 4 Where: CH 4D 4 4 V i i i MCF i = 1 when V i i = 1−(fH2O) i i i = 1/[1−(fH2O) i i i (f H2O 4 C i 4 n = The number of days in the week that the system is operational at that measurement point. To obtain the number of days in the week, divide the total number of hours that the system is operational by 24 hours per day. 0.0423 = Density of CH 4 520 °R = 520 degrees Rankine. T i P i 1,440 = Conversion factor (minutes/day). 0.454/1,000 = Conversion factor (metric ton/lb). (1) Values for V, C, T, P, and, if applicable, (f H2O (2) Quarterly total CH 4 4 Where: CH 4DTotal 4 4 (CH 4D i,j 4 4 m = Number of monitoring points. w = Number of weeks in the quarter during which the degasification system is operated. (c) If gas from a degasification system or ventilation system is sold, used onsite, or otherwise destroyed (including by flaring or VAM oxidation), you must calculate the quarterly CH 4 4 4 Where: CH 4Destroyed 4 CH 4 4 DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. (1) Calculate total CH 4 Where: CH 4DestroyedTotal 4 4 CH 4Destroyed 4 d = Number of onsite destruction devices and points of offsite transport. (2) [Reserved] (d) You must calculate the quarterly measured net CH 4 Where: CH 4 4 CH 4VTotal 4 4V CH 4DTotal 4 4D CH 4DestroyedTotal 4 (e) For the methane collected from degasification and/or ventilation systems that is destroyed on site and is not a fuel input for energy generation or use (those emissions are monitored and reported under Subpart C of this part), you must estimate the CO 2 Where: CO 2 2 4 CH 4Destroyedonsite 4 4 44/16 = Ratio of molecular weights of CO 2 4 [75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 78 FR 71967, Nov. 29, 2013; 81 FR 89264, Dec. 9, 2016; 89 FR 31938, Apr. 25, 2024] § 98.324 Monitoring and QA/QC requirements. (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) For CH 4 4 (1) Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and, if applicable, moisture content. The sampling and measurements must be made at the same locations as Mine Safety and Health Administration (MSHA) inspection samples are taken, and should be taken when the mine is operating under normal conditions. You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, Coal Mine Safety and Health General Inspection Procedures Handbook, Handbook Number: PH16-V-1 (incorporated by reference, see § 98.7). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection. (2) Obtain results of the quarterly (or more frequent) testing performed by MSHA for the methane flowrate. At the same location and within seven days of the MSHA sampling, make measurements of temperature and pressure using the same procedures specified in paragraph (b)(1) of this section. The annual average barometric pressure from the nearest National Oceanic and Atmospheric Administration (NOAA) weather service station may be used as a default for pressure. If the MSHA data for methane flow is provided in the units of actual cubic feet of methane per day, the methane flow data is inserted into Equation FF-1 of this section in place of the value for V and the variables MCF, C/100%, and 1440 are removed from the equation. (3) Monitor emissions through the use of one or more continuous emission monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems. (c) For CH 4 4 (1) Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems. (2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification monitoring site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in § 98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection. (3) If the CH 4 4 (i) The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and (ii) The grab sample, if using grab samples, at the time of the sample. (d) Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section. (1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7). (2) As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH 4 (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in § 98.323 and in paragraphs (b) and (c) of this section. You must calibrate the instrument with CH 4 4 (ii) Determine a correction factor that will be used with the gaseous organic concentrations measured in paragraph (i) of this section. The correction factor must be determined at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(C) of this section. (A) Take a minimum of three grab samples of the gas with a minimum of 20 minutes between samples and determine the methane composition of the gas using one of the methods specified in paragraph (d)(1) of this section. (B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the gaseous organic concentration of the gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of this section. (C) Determine the arithmetic average methane concentration and the arithmetic average gaseous organic concentration of the samples analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the correction factor. (iii) Calculate the CH 4 Where: C CH4 4 f NMOC C TGOC (e) All flow meters and gas composition monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using the applicable methods specified in paragraphs (d), and (e)(1) through (e)(7) of this section. Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Flow meters and gas composition monitors shall be recalibrated either at the minimum frequency specified by the manufacturer or annually. The operator shall operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see (f) For CH 4 4 (g) All temperature, pressure, and moisture content monitors must be operated and calibrated using the procedures and frequencies specified by the manufacturer. (h) The owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices. The estimated accuracy of measurements and the technical basis for the estimated accuracy shall be recorded. [75 FR 39763, July 12, 2010, as amended at 76 FR 73901, Nov. 29, 2011; 78 FR 71967, Nov. 29, 2013; 81 FR 89265, Dec. 9, 2016] § 98.325 Procedures for estimating missing data. (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., (b) For each missing value of CH 4 [75 FR 39763, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011] § 98.326 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each mine: (a) Quarterly CH 4 4 4 (b) Weekly CH 4 4 (c) Quarterly CH 4 4 (d) Quarterly CH 4 4 (e) Quarterly CO 2 4 e.g., 2 (f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF-1 of this subpart. Specify whether the volumetric flow rate measurement at each ventilation monitoring point is on dry basis or wet basis; and, if a flow meter is used, indicate whether or not the flow meter automatically corrects for moisture content. (g) Quarterly CH 4 4 (h) Weekly volumetric flow rate used to calculate CH 4 (i) Quarterly CH 4 4 4 (j) Weekly volumetric flow rate used to calculate CH 4 (k) Weekly CH 4 4 (l) Dates in quarterly reporting period where active ventilation of mining operations is taking place. (m) Dates in quarterly reporting period where degasification of mining operations is taking place. (n) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable. (o) Temperature (°R), pressure (atm), moisture content (if applicable), and the moisture correction factor (if applicable) used in Equations FF-1 and FF-3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF-9 of this subpart was required. Moisture content is required to be reported only if CH 4 4 (p) For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site. If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent). (q) A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters), and the annual operating hours of the gas collection system. (r) Identification information and description for each well, shaft, and vent hole, including paragraphs (r)(1) through (r)(3) of this section: (1) Indication of whether the well, shaft, or vent hole is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used. (2) Start date and close date of each well, shaft, and vent hole. If the well, shaft, or vent hole is operating through the end of the reporting year, December 31st of the reporting year shall be the close date for purposes of reporting. (3) Number of days the well, shaft, or vent hole was in operation during the reporting year. To obtain the number of days in the reporting year, divide the total number of hours that the system was in operation by 24 hours per day. (s) For each centralized monitoring point, identification of the wells and shafts included in the point. Note which method (sampling or continuous monitoring) was used. (t) Mine Safety and Health Administration (MSHA) identification number for this coal mine. [75 FR 39763, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011; 78 FR 71967, Nov. 29, 2013; 81 FR 89265, Dec. 9, 2016; 89 FR 31938, Apr. 25, 2024] § 98.327 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the following records: (a) Calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. (b) Records of gas sales. (c) Logbooks of parameter measurements. (d) Laboratory analyses of samples. § 98.328 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart GG—Zinc Production § 98.330 Definition of the source category. The zinc production source category consists of zinc smelters and secondary zinc recycling facilities. § 98.331 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.332 GHGs to report. You must report: (a) CO 2 (b) CO 2 4 2 (c) CO 2 4 2 § 98.333 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) Calculate and report under this subpart the process or combined process and combustion CO 2 (b) Calculate and report under this subpart the process CO 2 (1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO 2 Where: E CO2k 2 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion factor to convert tons to metric tons. (Zinc) k (C Zinc k (Flux) k (C Flux k (Electrode) k (C Electrode k (Carbon) k (C Carbon k (2) You must determine the CO 2 Where: CO 2 2 E CO2 k 2 n = Total number of Waelz kilns or electrothermic furnaces at facility used for the zinc production. (c) If GHG emissions from a Waelz kiln or electrothermic furnace are vented through the same stack as any combustion unit or process equipment that reports CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 89 FR 31938, Apr. 25, 2024] § 98.334 Monitoring and QA/QC requirements. If you determine CO 2 (a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records 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 total mass for the materials consumed each calendar month and sum the monthly mass to determine the annual mass for each input material. (b) For each input 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. (1) Information provided by your material supplier. (2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon-containing input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. 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. (i) Using ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7), analyze zinc bearing materials. (ii) Using 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), analyze carbonaceous reducing agents and carbon electrodes. (iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7), analyze flux materials such as limestone or dolomite. § 98.335 Procedures for estimating missing data. For the carbon input procedure in § 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, 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) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) For missing records of the carbon content of inputs for facilities that estimate emissions using the carbon input procedure in § 98.333(b); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.335(b) if data are missing. (b) For missing records of the annual mass of carbon-containing inputs using the carbon input procedure in § 98.333(b), the substitute data value must be based on the best available estimate of the mass of the input material from all available process data or information used for accounting purposes, such as purchase records. § 98.336 Data reporting requirements. 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, for each Waelz kiln or electrothermic furnace. (a) If a CEMS is used to measure CO 2 (1) Annual zinc product production capacity (tons). (2) Annual production quantity for each zinc product (tons). (3) Annual facility production quantity for each zinc product (tons). (4) Number of Waelz kilns at each facility used for zinc production. (5) Number of electrothermic furnaces at each facility used for zinc production. (6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons). (b) If a CEMS is not used to measure CO 2 (1) Identification number and annual process CO 2 (2) Annual zinc product production capacity (tons). (3) Annual production quantity for each zinc product (tons). (4) Number of Waelz kilns at each facility used for zinc production. (5) Number of electrothermic furnaces at each facility used for zinc production. (6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons). (7) [Reserved] (8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method. (9) If carbon content of each carbon-containing input material charged to each kiln or furnace is based on self measurement, the ASTM Standard Test Method used. (10) [Reserved] (11) Whether carbon content of the carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method. (12) If carbon content of carbon electrode used in each furnace is based on self measurement, the ASTM standard method used. (13) If you use the missing data procedures in § 98.335(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. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 79 FR 63799, Oct. 24, 2014; 89 FR 31938, Apr. 25, 2024] § 98.337 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each zinc production facility. (a) If a CEMS is used to measure emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a): (1) Monthly facility production quantity for each zinc product (tons). (2) Annual operating hours for all Waelz kilns and electrothermic furnaces used in zinc production. (b) If a CEMS is not used to measure emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(7) of this section. (1) Records of all analyses and calculations conducted for data reported as listed in § 98.336(b). (2) Annual operating hours for Waelz kilns and electrothermic furnaces used in zinc production. (3) Monthly production quantity for each zinc product (tons). (4) Monthly mass of zinc bearing materials, flux materials (e.g., limestone, dolomite), and carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace (tons). (5) Sampling and analysis records for carbon content of zinc bearing materials, flux materials (e.g., limestone, dolomite), carbonaceous materials (e.g., coal, coke), charged to the kiln or furnace (percent by weight, expressed as a decimal fraction). (6) Monthly mass of carbon electrode consumed in for each electrothermic furnace (tons). (7) Sampling and analysis records for carbon content of electrode materials. (8) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each Waelz kiln or electrothermic furnace, as applicable to your facility, including documentation of any materials excluded from Equation GG-1 of this subpart that contribute less than 1 percent of the total carbon inputs to the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (c) Verification software records. (1) Annual mass of zinc bearing material charged to kiln or furnace (tons) (Equation GG-1 of § 98.333). (2) Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace (percent by weight, expressed as a decimal fraction) (Equation GG-1). (3) Annual mass of flux materials (e.g., limestone, dolomite) charged to each kiln or furnace (tons) (Equation GG-1). (4) Carbon content of the flux materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1). (5) Annual mass of carbon electrode consumed in each furnace (tons) (Equation GG-1). (6) Carbon content of the carbon electrode consumed in each furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1). (7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each kiln or furnace (tons) (Equation GG-1). (8) Carbon content of the carbonaceous materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1). (9) Identify whether each unit is a Waelz kiln or an electrothermic furnace. [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63799, Oct. 24, 2014] § 98.338 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart HH—Municipal Solid Waste Landfills § 98.340 Definition of the source category. (a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980, unless all three of the following conditions apply. (1) The MSW landfill did not receive waste on or after January 1, 2013. (2) The MSW landfill had CH 4 4 (3) The owner or operator of the MSW landfill was not required to submit an annual report under any requirement of this part in any reporting year prior to 2013. (b) This source category does not include Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) hazardous waste landfills, construction and demolition waste landfills, or industrial waste landfills. (c) This source category consists of the following sources at municipal solid waste (MSW) landfills: Landfills, landfill gas collection systems, and landfill gas destruction devices (including flares). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 78 FR 71968, Nov. 29, 2013] § 98.341 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of § 98.2(a)(1). § 98.342 GHGs to report. (a) You must report CH 4 4 (b) You must report CH 4 (c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 § 98.343 Calculating GHG emissions. (a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH 4 (1) Calculate annual modeled CH 4 Where: G CH4 4 x = Year in which waste was disposed. S = Start year of calculation. Use the year 1960 or the opening year of the landfill, whichever is more recent. T = Reporting year for which emissions are calculated. W X MCF = Methane correction factor (fraction). Use the default value of 1 unless there is active aeration of waste within the landfill during the reporting year. If there is active aeration of waste within the landfill during the reporting year, use either the default value of 1 or select an alternative value no less than 0.5 based on site-specific aeration parameters. DOC = Degradable organic carbon from Table HH-1 of this subpart [fraction (metric tons C/metric ton waste)]. DOC F F = Fraction by volume of CH 4 k = Rate constant from Table HH-1 to this subpart (yr −1 (2) For years when material-specific waste quantity data are available, apply equation HH-1 to this section for each waste quantity type and sum the CH 4 4 F (3) Beginning in the first emissions reporting year and for each year thereafter, if scales are in place, you must determine the annual quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill using paragraph (a)(3)(i) of this section for all containers and for all vehicles used to haul waste to the landfill, except for passenger cars, light duty pickup trucks, or waste loads that cannot be measured using the scales due to physical limitations (load cannot physically access or fit on the scale) and/or operational limitations of the scale (load exceeding the limits or sensitivity range of the scale). If scales are not in place, you must use paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For waste hauled to the landfill in passenger cars or light duty pickup trucks, you may use either paragraph (a)(3)(i) or paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For loads that cannot be measured using the scales due to physical and/or operational limitations of the scale, you must use paragraph (a)(3)(ii) of this section or similar engineering calculations to determine the annual quantity of waste disposed. The approach used to determine the annual quantity of waste disposed of must be documented in the monitoring plan. (i) Use direct mass measurements of each individual load received at the landfill using either of the following methods: (A) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; weigh using mass scales each vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference in the two mass measurements; and determine the annual quantity of waste received as the sum of all waste loads received during the year. Alternatively, you may determine annual quantity of waste by summing the weights of all vehicles and containers entering the landfill and subtracting from it the sum of all the weights of vehicles and containers after they have off-loaded the waste in the landfill. (B) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; determine a representative tare weight by vehicle or container type by weighing no less than 5 of each type of vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference between the measured weight in and the tare weight determined for that container/vehicle type; and determine the annual quantity of waste received as the sum of all waste loads received during the year. (ii) Determine the working capacity in units of mass for each type of container or vehicle used to haul waste to the landfill ( e.g., (4) For years prior to the first emissions reporting year, use methods in paragraph (a)(3) of this section when waste disposal quantity data are readily available. When waste disposal quantity data are not readily available, W X (i) Assume all prior years waste disposal quantities are the same as the waste quantity in the first year for which waste quantities are available. (ii) Use the estimated population served by the landfill in each year, the values for national average per capita waste disposal rates found in Table HH-2 to this subpart, and calculate the waste quantity landfilled using Equation HH-2 of this section. where: W X POP X WDR X (iii) Use a constant average waste disposal quantity calculated using Equation HH-3 of this section for each year the landfill was in operation (i.e., from the first year accepting waste until the last year for which waste disposal data is unavailable, inclusive). where: W X LFC = Landfill capacity or, for operating landfills, capacity of the landfill used (or the total quantity of waste-in-place) at the end of the year prior to the year when waste disposal data are available from design drawings or engineering estimates (metric tons). YrData = Year in which the landfill last received waste or, for operating landfills, the year prior to the first reporting year when waste disposal data is first available from company records, or best available data. YrOpen = Year in which the landfill first received waste from company records or best available data. If no data are available for estimating YrOpen for a closed landfill, use 30 years as the default operating life of the landfill. (b) For landfills with gas collection systems, calculate the quantity of CH 4 (1) If you continuously monitor the flow rate, CH 4 4 4 4 where: R = Annual quantity of recovered CH 4 4 N = Total number of measurement periods in a year. Use daily averaging periods for a continuous monitoring system and N = 365 (or N = 366 for leap years). For monthly sampling, as provided in paragraph (b)(2) of this section, use N = 12. n = Index for measurement period. (V) n n n (K MC n MC n n n MC n H 2 O n n n MC n H2O n n n (f H 2 O n (C CH4 n 4 0.0423 = Density of CH 4 (T) n (P) n 0.454/1,000 = Conversion factor (metric ton/lb). (2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH 4 4 (i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each month and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section. (ii) Determine the CH 4 (iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content: (A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements. (B) If the CH 4 4 (c) For all landfills, calculate CH 4 4 4 (1) Calculate CH 4 4 CH 4 Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH 4 G CH4 4 OX = Oxidation fraction. Use the appropriate oxidation fraction default value from Table HH-4 of this subpart. (2) For landfills that do not have landfill gas collection systems, the CH 4 4 (3) For landfills with landfill gas collection systems, calculate CH 4 (i) Calculate CH 4 4 4 Where: Emissions = Methane emissions from the landfill in the reporting year (metric tons CH 4 G CH4 4 4 N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH 4 R n 4 4 OX = Oxidation fraction. Use the appropriate oxidation fraction default value from table HH-4 to this subpart. DE n 4 n f Dest,n Dest,n 4 Dest,n Dest (ii) Calculate CH 4 4 4 Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH 4 Emissions = Methane emissions from the landfill in the reporting year (metric tons CH 4 C = Number of landfill gas collection systems operated at the landfill. X = Number of landfill gas measurement locations associated with landfill gas collection system “c”. N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH 4 S (c=1) C S (x=1) X R x,c 4 4 R n 4 4 CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, measurement practices, and cover system materials from table HH-3 to this subpart. If area by soil cover type information is not available, use applicable default value for CE4 in table HH-3 to this subpart for all areas under active influence of the collection system. f Rec,c OX = Oxidation fraction. Use appropriate oxidation fraction default value from table HH-4 to this subpart. DE n 4 n f Dest,n Dest,n 4 Dest,n Dest [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66470, Oct. 28, 2010; 78 FR 71968, Nov. 29, 2013; 89 FR 31938, Apr. 25, 2024] § 98.344 Monitoring and QA/QC requirements. (a) Mass measurement equipment used to determine the quantity of waste landfilled on or after January 1, 2010 must meet the requirements for weighing equipment as described in “Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices” NIST Handbook 44 (2009) (incorporated by reference, see § 98.7). (b) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 (1) Method 18 at 40 CFR part 60, appendix A-6. (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography. (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7). (6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of this section. (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with methane and determine the total gaseous organic concentration as carbon (or as methane; K = 1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7). (ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section. (A) Take a minimum of three grab samples of the landfill gas with a minimum of 20 minutes between samples and determine the methane composition of the landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(5) of this section. (B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the landfill gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (b)(6)(i) of this section. (C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor. (iii) Calculate the methane concentration as specified in Equation HH-9 of this section. Where: C CH4 f NMOC C TGOC (c) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas using one of the methods specified in paragraphs (c)(1) through (c)(8) of this section or as specified by the manufacturer. Each gas flow meter shall be recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.343(b)(2)(i), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content. (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see (8) Method 2A or 2D at 40 CFR part 60, appendix A-1. (d) All temperature, pressure, and if necessary, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer. (e) For landfills electing to measure the fraction by volume of CH 4 4 2 2 (2) Use Equation HH-10 of this section to correct the measured CH 4 4 Where: F = Fraction by volume of CH 4 C CH4 4 20.9 c 2 20.9 = O 2 %O 2 2 (f) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices, and the technical basis for these estimates shall be recorded. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66472, Oct. 28, 2010; 78 FR 71969, Nov. 29, 2013] § 98.345 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section. (a) For each missing value of the CH 4 (b) For missing gas flow rates, 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 the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period. (c) For missing daily waste disposal quantity data for disposal in the reporting year, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71970, Nov. 29, 2013] § 98.346 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill. (a) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used), an indication as to whether scales are present at the landfill, and the waste disposal quantity for each year of landfilling required to be included when using Equation HH-1 of this subpart (in metric tons, wet weight). (b) Method for estimating reporting year and historical waste disposal quantities, reason for its selection, and the range of years it is applied. For years when waste quantity data are determined using the methods in § 98.343(a)(3), report separately the quantity of waste determined using the methods in § 98.343(a)(3)(i) and the quantity of waste determined using the methods in § 98.343(a)(3)(ii). For historical waste disposal quantities that were not determined using the methods in § 98.343(a)(3), provide the population served by the landfill for each year the Equation HH-2 of this subpart is applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide the value of landfill capacity (LFC) used in the calculation. (c) Waste composition for each year required for Equation HH-1 of this subpart, in percentage by weight, for each waste category listed in Table HH-1 to this subpart that is used in Equation HH-1 of this subpart to calculate the annual modeled CH 4 (d) For each waste type used to calculate CH 4 (1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOC F (2) Decay rate (k) value used in the calculations. (e) Fraction of CH 4 4 (f) The surface area of the landfill containing waste (in square meters), identification of the type(s) of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures). (g) The modeled annual methane generation rate for the reporting year (metric tons CH 4 (h) An indication of the applicability of part 60 or part 62 of this chapter requirements to the landfill (part 60, subparts WWW and XXX of this chapter, approved state plan implementing part 60, subparts Cc or Cf of this chapter, Federal plan as implemented at part 62, subparts GGG or OOO of this chapter, or not subject to part 60 or part 62 of this chapter municipal solid waste landfill rules), and if the landfill is subject to a part 60 or part 62 of this chapter municipal solid waste landfill rule, an indication of whether the landfill gas collection system is required under part 60 or part 62 of this chapter. (i) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH 4 (j) For landfills with gas collection systems, you must report: (1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520 °R or 60 degrees Fahrenheit and 1 atm). (2) Annual average CH 4 (3) Monthly average temperature and pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature and/or pressure is incorporated into internal calculations run by the monitoring equipment. (4) An indication as to whether flow was measured on a wet or dry basis, an indication as to whether CH 4 (5) The number of gas collection systems at the landfill facility. (6) For each gas collection system at the facility report: (i) A unique name or ID number for the gas collection system. (ii) A description of the gas collection system (manufacturer, capacity, and number of wells). (iii) The annual hours the gas collection system was operating normally. Do not include periods of shut down or poor operation, such as times when pressure, temperature, or other parameters indicative of operation are outside of normal variances, in the annual operating hours. (iv) The number of measurement locations associated with the gas collection system. (v) For each measurement location associated with the gas collection system, report: (A) A unique name or ID number for the measurement location. (B) Annual quantity of recovered CH 4 4 (C) An indication of whether destruction occurs at the landfill facility, off-site, or both for the measurement location. (D) If destruction occurs at the landfill facility for the measurement location (in full or in part), also report the number of destruction devices associated with the measurement location that are located at the landfill facility and the information in paragraphs (j)(6)(v)(D)(1) through (6) of this section for each destruction device located at the landfill facility. ( 1 ( 2 i.e., ( 3 ( 4 ( 5 ( 6 (7) The following information about the landfill. (i) The surface area (square meters) and estimated waste depth (meters) for each area specified in table HH-3 to this subpart. (ii) The estimated gas collection system efficiency for the landfill. (iii) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at the landfill. (8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH 4 (9) Methane generation (G CH4 CH4 (10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH 4 (11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH 4 (12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH 4 (13) Methane emissions for the landfill ( i.e., 4 CH4 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66472, Oct. 28, 2010; 78 FR 71970, Nov. 29, 2013; 81 FR 89266, Dec. 9, 2016; 89 FR 31940, Apr. 25, 2024] § 98.347 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. You must retain records of all measurements made to determine tare weights and working capacities by vehicle/container type if these are used to determine the annual waste quantities. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66473, Oct. 28, 2010] § 98.348 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Construction and demolition (C&D) waste landfill Destruction device Final cover Industrial waste landfill Intermediate or interim cover Landfill capacity landfill capacity Leachate recirculation Passive vent Solid waste et seq. Working capacity [75 FR 66473, Oct. 28, 2010, as amended at 78 FR 71970, Nov. 29, 2013; 81 FR 89266, Dec. 9, 2016] Table HH-1 to Subpart HH of Part 98—Emissions Factors, Oxidation Factors and Methods Table HH-1 to Subpart HH of Part 98—Emissions Factors, Oxidation Factors and Methods Factor Default value Units DOC and k values—Bulk waste option: DOC (bulk waste) for disposal years prior to 2010 0.20 Weight fraction, wet basis. DOC (bulk waste) for disposal years 2010 and later 0.17 Weight fraction, wet basis. k (precipitation plus recirculated leachate a 0.02 yr - 1 k (precipitation plus recirculated leachate a 0.033 yr - 1 k (precipitation plus recirculated leachate a 0.038 yr - 1 k (precipitation plus recirculated leachate a 0.067 yr - 1 k (precipitation plus recirculated leachate a 0.057 yr - 1 k (precipitation plus recirculated leachate a 0.098 yr - 1 DOC and k values—Modified bulk MSW option: DOC (bulk MSW, excluding inerts and C&D waste) for disposal years prior to 2010 0.31 Weight fraction, wet basis. DOC (bulk MSW, excluding inerts and C&D waste) for disposal years 2010 and later 0.27 Weight fraction, wet basis. DOC (inerts, e.g., 0.00 Weight fraction, wet basis. DOC (C&D waste) 0.08 Weight fraction, wet basis. k (bulk MSW, excluding inerts and C&D waste) for disposal years prior to 2010 0.02 to 0.057 b yr - 1 k (bulk MSW, excluding inerts and C&D waste) for disposal years 2010 and later 0.033 to 0.098 b yr - 1 k (inerts, e.g., 0.00 yr - 1 k (C&D waste) 0.02 to 0.04 b yr - 1 DOC and k values—Waste composition option: DOC (food waste) 0.15 Weight fraction, wet basis. DOC (garden) 0.2 Weight fraction, wet basis. DOC (paper) 0.4 Weight fraction, wet basis. DOC (wood and straw) 0.43 Weight fraction, wet basis. DOC (textiles) 0.24 Weight fraction, wet basis. DOC (diapers) 0.24 Weight fraction, wet basis. DOC (sewage sludge) 0.05 Weight fraction, wet basis. DOC (inerts, e.g., 0.00 Weight fraction, wet basis. DOC (Uncharacterized MSW 0.32 Weight fraction, wet basis. k (food waste) 0.06 to 0.185 c yr - 1 k (garden) 0.05 to 0.10 c yr - 1 k (paper) 0.04 to 0.06 c yr - 1 k (wood and straw) 0.02 to 0.03 c yr - 1 k (textiles) 0.04 to 0.06 c yr - 1 k (diapers) 0.05 to 0.10 c yr - 1 k (sewage sludge) 0.06 to 0.185 c yr - 1 k (inerts, e.g., 0.00 yr - 1 k (uncharacterized MSW) 0.033 to 0.098 b yr - 1 Other parameters—All MSW landfills: MCF 1 DOC F 0.5 F 0.5 OX See table HH-4 to this subpart DE 0.99 a b c [89 FR 31940, Apr. 25, 2024] Table HH-2 to Subpart HH of Part 98—U.S. Per Capita Waste Disposal Rates Year Waste per capita 1950 0.63 1951 0.63 1952 0.63 1953 0.63 1954 0.63 1955 0.63 1956 0.63 1957 0.63 1958 0.63 1959 0.63 1960 0.63 1961 0.64 1962 0.64 1963 0.65 1964 0.65 1965 0.66 1966 0.66 1967 0.67 1968 0.68 1969 0.68 1970 0.69 1971 0.69 1972 0.70 1973 0.71 1974 0.71 1975 0.72 1976 0.73 1977 0.73 1978 0.74 1979 0.75 1980 0.75 1981 0.76 1982 0.77 1983 0.77 1984 0.78 1985 0.79 1986 0.79 1987 0.80 1988 0.80 1989 0.83 1990 0.82 1991 0.76 1992 0.74 1993 0.76 1994 0.75 1995 0.70 1996 0.68 1997 0.69 1998 0.75 1999 0.75 2000 0.80 2001 0.91 2002 1.02 2003 1.02 2004 1.01 2005 0.98 2006 0.95 2007 0.95 2008 0.95 2009 and all later years 0.95 [78 FR 71971, Nov. 29, 2013] Table HH-3 to Subpart HH of Part 98—Landfill Gas Collection Efficiencies Table HH-3 to Subpart HH of Part 98—Landfill Gas Collection Efficiencies Description Term ID Landfill gas collection A1: Area with no waste in-place Not applicable; do not use this area in the calculation. A2: Area without active gas collection, regardless of cover type CE2 0%. A3: Area with daily soil cover and active gas collection CE3 50%. A4: Area with an intermediate soil cover, or a final soil cover not meeting the criteria for A5 below, and active gas collection CE4 65%. A5: Area with a final soil cover of 3 feet or thicker of clay or final cover (as approved by the relevant agency) and/or geomembrane cover system and active gas collection CE5 85%. Area weighted average collection efficiency for landfills CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2 + A3 + A4 + A5). [89 FR 31941, Apr. 25, 2024] Table HH-4 to Subpart HH of Part 98—Landfill Methane Oxidation Fractions Under these conditions: Use this landfill methane oxidation I. For all reporting years prior to the 2013 reporting year C1: For all landfills regardless of cover type or methane flux 0.10 II. For the 2013 reporting year and all subsequent years C2: For landfills that have a geomembrane (synthetic) cover or other non-soil barrier meeting the definition of final cover with less than 12 inches of cover soil for greater than 50% of the landfill area containing waste 0.0 C3: For landfills that do not meet the conditions in C2 above and for which you elect not to determine methane flux 0.10 C4: For landfills that do not meet the conditions in C2 or C3 above and that do not have final cover, or intermediate or interim cover a 0.10 C5: For landfills that do not meet the conditions in C2 or C3 above and that have final cover, or intermediate or interim cover a b 2 0.35 C6: For landfills that do not meet the conditions in C2 or C3 above and that have final cover or intermediate or interim cover a b 2 0.25 C7: For landfills that do not meet the conditions in C2 or C3 above and that have final cover or intermediate or interim cover a b 2 0.10 a b 2 For equation HH-5 to § 98.343, or for equation TT-6 to § 98.463, MF = K × G CH4 For equation HH-6 to § 98.343, For equation HH-7 to § 98.343, For equation HH-8 to § 98.343, Where: MF = Methane flux rate from the landfill in the reporting year (grams per square meter per day, g/m 2 K = unit conversion factor = 10 6 6 SArea = The surface area of the landfill containing waste at the beginning of the reporting year (square meters, m 2 G CH4 4 4 4 CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, measurement practices, and cover system materials from table HH-3 to this subpart. If area by soil cover type information is not available, use applicable default value for CE4 in table HH-3 to this subpart for all areas under active influence of the collection system. C = Number of landfill gas collection systems operated at the landfill. X = Number of landfill gas measurement locations associated with landfill gas collection system “c”. N = Number of landfill gas measurement locations (associated with a destruction device or gas sent off-site). If a single monitoring location is used to monitor volumetric flow and CH 4 c =1 C x =1 X R x,c 4 th 4 R n 4 th 4 f Rec,c [78 FR 71971, Nov. 29, 2013, as amended at 81 FR 89266, Dec. 9, 2016; 89 FR 31941, Apr. 25, 2024] Subpart II—Industrial Wastewater Treatment Source: 75 FR 39767, July 12, 2010, unless otherwise noted. § 98.350 Definition of source category. (a) This source category consists of anaerobic processes used to treat industrial wastewater and industrial wastewater treatment sludge at facilities that perform the operations listed in this paragraph. (1) Pulp and paper manufacturing. (2) Food processing. (3) Ethanol production. (4) Petroleum refining. (b) An anaerobic process 2 4 (1) An anaerobic reactor e.g., (2) An anaerobic sludge digester (3) An anaerobic lagoon (c) This source category does not include municipal wastewater treatment plants or separate treatment of sanitary wastewater at industrial sites. [75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011] § 98.351 Reporting threshold. You must report GHG emissions under this subpart if your facility meets all of the conditions under paragraphs (a) or (b) of this section: (a) Petroleum refineries and pulp and paper manufacturing. (2) The facility meets the requirements of either § 98.2(a)(1) or (2). (3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge. (b) Ethanol production and food processing facilities. (2) The facility meets the requirements of § 98.2(a)(2). (3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge. § 98.352 GHGs to report. (a) You must report CH 4 4 4 (b) You must report CH 4 4 (c) You must report CH 4 4 (d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 [75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011] § 98.353 Calculating GHG emissions. (a) For each anaerobic reactor and anaerobic lagoon, estimate the annual mass of CH 4 (1) If you measure the concentration of organic material entering the anaerobic reactors or anaerobic lagoon using methods for the determination of chemical oxygen demand (COD), then estimate annual mass of CH 4 Where: CH 4 n 4 n = Index for processes at the facility, used in Equation II-7. w = Index for weekly measurement period. Flow w 3 COD w 3 B 0 4 4 MCF = CH 4 0.001 = Conversion factor from kg to metric tons. (2) If you measure the concentration of organic material entering an anaerobic reactor or anaerobic lagoon using methods for the determination of 5-day biochemical oxygen demand (BOD 5 4 Where: CH 4 n 4 n = Index for processes at the facility, used in Equation II-7. w = Index for weekly measurement period. Flow w 3 BOD 5,w 3 B 0 4 4 5 MCF = CH 4 0.001 = Conversion factor from kg to metric tons. (b) For each anaerobic reactor and anaerobic lagoon from which biogas is not recovered, estimate annual CH 4 Where: CH 4 n 4 CH 4 n 4 (c) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some biogas is recovered, estimate the annual mass of CH 4 4 (1) If you continuously monitor CH 4 4 4 4 Where: R n 4 4 n = Index for processes at the facility, used in Equation II-7. M = Total number of measurement periods in a year. Use M = 365 (M = 366 for leap years) for daily averaging of continuous monitoring, as provided in paragraph (c)(1)of this section. Use M = 52 for weekly sampling, as provided in paragraph (c)(2)of this section. m = Index for measurement period. V m (K MC m = 1 when (V) m CH4 m = 1−(f H2O m m CH4 m = 1/[1−(f H2O m m CH4 m (f H2O m (C CH4 m 4 0.0423 = Density of CH 4 520 °R = 520 degrees Rankine. T m m P m m 0.454/1,000 = Conversion factor (metric ton/lb). (2) If you do not continuously monitor CH 4 4 4 (i) Determine the CH 4 4 (ii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content: (A) Determine the temperature and pressure in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements. (B) If the CH 4 4 (d) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, you must estimate both the annual mass of CH 4 4 (1) Estimate the annual mass of CH 4 Where: CH 4 n 4 n = Index for processes at the facility, used in Equation II-7. R n 4 4 CE = CH 4 (2) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, estimate the annual mass of CH 4 Where: CH 4 n 4 n = Index for processes at the facility, used in Equation II-7. CH 4 n 4 R n 4 4 DE 1 4 f Dest_1 Dest DE 2 4 f Dest_2 (e) Estimate the total mass of CH 4 Where: CH 4 T 4 n = Index for processes at the facility. CH 4 n 4 j = Total number of processes from which methane is emitted. [75 FR 39767, July 12, 2010, as amended at 76 FR 73903, Nov. 29, 2011; 78 FR 71972, Nov. 29, 2013] § 98.354 Monitoring and QA/QC requirements. (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) You must determine the concentration of organic material in wastewater treated anaerobically using analytical methods for COD or BOD 5 (c) You must collect samples representing wastewater influent to the anaerobic wastewater treatment process, following all preliminary and primary treatment steps ( e.g., 5 5 see see (d) You must measure the flowrate of wastewater entering anaerobic wastewater treatment process at least once each calendar week that the process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must measure the flowrate for the 24-hour period for which you collect samples analyzed for COD or BOD 5 5 (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see (2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see (3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference, see (4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, (incorporated by reference, see (5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, (incorporated by reference, see (e) All wastewater flow measurement devices must be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Wastewater flow measurement devices must be calibrated using the procedures specified by the device manufacturer. (f) For each anaerobic process (such as anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, you must make the measurements or determinations specified in paragraphs (f)(1) through (f)(3) of this section. (1) You must continuously measure the biogas flow rate as specified in paragraph (h) of this section and determine the cumulative volume of biogas recovered. (2) You must determine the CH 4 4 (3) As specified in § 98.353(c) and paragraph (h) of this section, you must determine temperature, pressure, and moisture content as necessary to accurately determine the biogas flow rate and CH 4 4 4 (g) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 (1) Method 18 at 40 CFR part 60, appendix A-6. (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see (5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see (6) As an alternative to the gas chromatography methods provided in paragraphs (g)(1) through (g)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the CH 4 (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with CH 4 4 (ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (g)(6)(ii)(A) through (g)(6)(ii)(C) of this section. (A) Take a minimum of three grab samples of the biogas with a minimum of 20 minutes between samples and determine the methane composition of the biogas using one of the methods specified in paragraphs (g)(1) through (g)(5) of this section. (B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the biogas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (g)(6)(i) of this section. (C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor. (iii) Calculate the CH 4 Where: C CH 4 4 f NMOC C TGOC (h) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, install, operate, maintain, and calibrate a gas flow meter capable of continuously measuring the volumetric flow rate of the recovered biogas using one of the methods specified in paragraphs (h)(1) through (h)(8) of this section or as specified by the manufacturer. Recalibrate each gas flow meter either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.353(c)(2)(iii), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content. (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and biogas composition. (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see (8) Method 2A or 2D at 40 CFR part 60, appendix A-1. (i) All temperature, pressure, and, moisture content monitors required as specified in paragraph (f) of this section must be calibrated using the procedures and frequencies where specified by the device manufacturer, if not specified use an industry accepted or industry standard practice. (j) All equipment (temperature, pressure, and moisture content monitors and gas flow meters and gas composition monitors) must be maintained as specified by the manufacturer. (k) If applicable, the owner or operator must document the procedures used to ensure the accuracy of measurements of COD or BOD 5 [75 FR 39767, July 12, 2010, as amended at 76 FR 73904, Nov. 29, 2011] § 98.355 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable ( e.g., (a) For each missing weekly value of COD or BOD 5 (b) For each missing value of the CH 4 (c) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. If, for a particular parameter, the “after” value is not obtained by the end of the reporting year, you may use the last quality-assured value obtained “before” the missing data period for the missing data substitution. You must document and keep records of the procedures you use for all such estimates. [75 FR 39767, July 12, 2010, as amended at 76 FR 73905, Nov. 29, 2011] § 98.356 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each wastewater treatment system. (a) Identify the anaerobic processes used in the industrial wastewater treatment system to treat industrial wastewater and industrial wastewater treatment sludge, provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered. Provide a description or diagram of the industrial wastewater treatment system, identifying the processes used, indicating how the processes are related to each other, and providing a unique identifier for each anaerobic process. Each anaerobic process must be identified as one of the following: (1) Anaerobic reactor. (2) Anaerobic deep lagoon (depth more than 2 meters). (3) Anaerobic shallow lagoon (depth less than 2 meters). (4) Anaerobic sludge digester. (b) For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon) you must report: (1) Weekly average COD or BOD 5 (2) Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated. (3) Maximum CH 4 0 (4) Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart. (5) Annual mass of CH 4 (6) If the facility performs an ethanol production processing operation as defined in § 98.358, you must indicate if the facility uses a wet milling process or a dry milling process. (c) For each anaerobic wastewater treatment process from which biogas is not recovered, you must report the annual CH 4 (d) For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report: (1) Annual quantity of CH 4 (2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction. (3) Weekly average CH 4 (4) Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calculations. (5) Whether flow was measured on a wet or dry basis, whether CH 4 (6) Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calculations. (7) CH 4 (8) Whether destruction occurs at the facility or off-site. If destruction occurs at the facility, also report whether a back-up destruction device is present at the facility, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), the destruction efficiency for the primary destruction device, and the destruction efficiency for the back-up destruction device (if present). (9) For each anaerobic process from which some biogas is recovered, you must report the annual CH 4 (e) The total mass of CH 4 [75 FR 39767, July 12, 2010, as amended at 76 FR 73905, Nov. 29, 2011; 81 FR 89267, Dec. 9, 2016] § 98.357 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. § 98.358 Definitions. Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part. Biogas 2 4 Dry milling Ethanol production Food processing see http://www.census.gov/eos/www/naics/. Industrial wastewater Industrial wastewater treatment sludge Wastewater treatment system Wet milling Weekly average [74 FR 56374, Oct. 30, 2009, as amended at 81 FR 89267, Dec. 9, 2016] Table II-1 to Subpart II of Part 98—Emission Factors Factors Default value Units B 0 0.25 Kg CH 4 B 0 5 0.60 Kg CH 4 5 MCF—anaerobic reactor 0.8 Fraction. MCF—anaerobic deep lagoon (depth more than 2 m) 0.8 Fraction. MCF—anaerobic shallow lagoon (depth less than 2 m) 0.2 Fraction. Table II-2 to Subpart II of Part 98—Collection Efficiencies of Anaerobic Processes Anaerobic process type Cover type Methane collection efficiency Covered anaerobic lagoon (biogas capture) Bank to bank, impermeable 0.975 Modular, impermeable 0.70 Anaerobic sludge digester; anaerobic reactor Enclosed Vessel 0.99 Subpart JJ—Manure Management § 98.360 Definition of the source category. (a) This source category consists of livestock facilities with manure management systems that emit 25,000 metric tons CO 2 (1) Table JJ-1 presents the minimum average annual animal population by animal group that is estimated to emit 25,000 metric tons CO 2 (2) (i) If a facility has more than one animal group present (e.g., swine and poultry), the facility must determine if they are required to report by calculating the combined animal group factor (CAGF) using equation JJ-1: Where: CAGF = Combined Animal Group Factor AAAP AG,Facility APTL AG (ii) If the calculated CAGF for a facility is less than 1, the facility is not required to report under this rule. If the CAGF is equal to or greater than 1, the facility must use more detailed applicability tables and tools to determine if they are required to report under this rule. (b) A manure management system (MMS) is a system that stabilizes and/or stores livestock manure, litter, or manure wastewater in one or more of the following system components: Uncovered anaerobic lagoons, liquid/slurry systems with and without crust covers (including but not limited to ponds and tanks), storage pits, digesters, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic treatment. (c) This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/range/paddock systems or land application activities or any method of manure utilization that is not listed in § 98.360(b). (d) This source category does not include manure management activities located off site from a livestock facility or off-site manure composting operations. § 98.361 Reporting threshold. Livestock facilities must report GHG emissions under this subpart if the facility meets the reporting threshold as defined in 98.360(a) above, contains a manure management system as defined in 98.360(b) above, and meets the requirements of § 98.2(a)(1). § 98.362 GHGs to report. (a) Livestock facilities must report annual aggregate CH 4 2 (1) Uncovered anaerobic lagoons. (2) Liquid/slurry systems (with and without crust covers, and including but not limited to ponds and tanks). (3) Storage pits. (4) Digesters, including covered anaerobic lagoons. (5) Solid manure storage. (6) Dry lots, including feedlots. (7) High-rise houses for poultry production (poultry without litter) (8) Poultry production with litter. (9) Deep bedding systems for cattle and swine. (10) Manure composting. (11) Aerobic treatment. (b) A livestock facility that is subject to this rule only because of emissions from manure management system components is not required to report emissions from subparts C through PP (other than subpart JJ) of this part. (c) A livestock facility that is subject to this part because of emissions from source categories described in subparts C through PP of this part is not required to report emissions under subpart JJ of this part unless emissions from manure management systems are 25,000 metric tons CO 2 § 98.363 Calculating GHG emissions. (a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual CH 4 Where: MMSC = Manure management systems component. TVS AT VS MMSC VS ss (B 0 AT 4 3 4 MCF MMSC 4 Where: TVS AT Population AT TAM AT VS AT (1) Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) must be estimated by performing an animal inventory or review of facility records once each reporting year. (2) Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) must be estimated each year using the average number of days each animal is kept at the facility and the number of animals produced annually, and an equation similar or equal to Equation JJ-4 below, adapted from Equation 10.1 in 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Where: Population AT Days onsite AT NAPA AT (b) For each digester, calculate the total amount of CH 4 Where: CH 4 AD 4 AD = Number of anaerobic digesters at the manure management facility. CH 4 4 4 CH 4 4 4 CH 4 4 (1) For each digester, calculate the annual CH 4 4 4 4 Where: CH 4 4 4 V = Average annual volumetric flow rate, calculated in Equation JJ-7 of this subsection (cubic feet CH 4 C = Average annual CH 4 0.0423 = Density of CH 4 T = Average annual temperature at which flow is measured, calculated in Equation JJ-9 of this section (°R). P = Average annual pressure at which flow is measured, calculated in Equation JJ-10 of this section (atm). (2) For each digester, calculate the average annual volumetric flow rate, CH 4 Where: V = Average annual volumetric flow rate (cubic feet CH 4 OD = Operating days, number of days per year that that the digester was operating (days/yr). V n Where: C = Average annual CH 4 OD = Operating days, number of days per year that the digester was operating (days/yr). C n 4 Where: T = Average annual temperature at which flow is measured (°R). OD = Operating days, number of days per year that the digester was operating (days/yr). T n Where: P = Average annual pressure at which flow is measured (atm). OD = Operating days, number of days per year that the digester was operating (days/yr). P n (3) For each digester, calculate the CH 4 Where: CH 4 4 CH 4 4 4 DE = CH 4 OH = Number of hours combustion device is functioning in reporting year. Hours = Hours in reporting year. (4) For each digester, calculate the CH 4 Where: CH 4 CH 4 4 4 CE = CH 4 (c) For each MMS component, estimate the annual N 2 Where: N ex AT N ex,MMSC ex N ss EF MMSC 2 Where: N ex AT Population AT TAM AT N AT (d) Estimate the annual total facility emissions using Equation JJ-15 of this section. Where: CH 4 MMS CH 4 AD 21 = Global Warming Potential of CH 4 Direct N 2 310 = Global Warming Potential of N 2 § 98.364 Monitoring and QA/QC requirements. (a) Perform an annual animal inventory or review of facility records (for static populations) or population calculation (for growing populations) to determine the average annual animal population for each animal type (see description in § 98.363(a)(1) and (2)). (b) Perform an analysis on your operation to determine the fraction of total manure by weight for each animal type that is managed in each on-site manure management system component. If your system changes from previous reporting periods, you must reevaluate the fraction of total manure managed in each system component. (c) The CH 4 see see (d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. All equipment (temperature and pressure monitors) shall be maintained as specified by the manufacturer. (e) For digesters with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate to provide data for the GHG emissions calculations, using the applicable methods specified in paragraphs (e)(1) through (e)(6) of this section or as specified by the manufacturer. (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see (5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see (6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see (f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. (g) Each gas flow meter shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. Each gas flow meter must have a rated accuracy of ±5 percent or lower and be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH 4 § 98.365 Procedures for estimating missing data. (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 fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section. (b) For missing gas flow rates or CH 4 § 98.366 Data reporting requirements. (a) In addition to the information required by § 98.3(c), each annual report must contain the following information: (1) List of manure management system components at the facility. (2) Fraction of manure from each animal type that is handled in each manure management system component. (3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ-4 for growing populations. (4) Average number of days that growing animals are kept at the facility (for each animal type). (5) The number of animals produced annually for growing populations (for each animal type). (6) Typical animal mass (for each animal type). (7) Total facility emissions (results of Equation JJ-15). (8) CH 4 (9) VS value used (for each animal type). (10) B 0 (11) Methane conversion factor used for each MMS component. (12) Average ambient temperature used to select each methane conversion factor. (13) N 2 (14) N value used for each animal type. (15) N 2 (b) Facilities with anaerobic digesters must also report: (1) CH 4 (2) CH 4 (3) CH 4 (4) CH 4 (5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7). (6) Average annual CH 4 (7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ-9). (8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ-10). (9) Destruction efficiency used for each digester. (10) Number of days per year that each digester was operating. (11) Collection efficiency used for each digester. § 98.367 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration. § 98.368 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table JJ-1 to Subpart JJ of Part 98—Animal Population Threshold Level Below Which Facilities Are Not Required To Report Emissions Under Subpart JJ 1 2 Animal group Average annual animal population (Head) 3 Beef 29,300 Dairy 3,200 Swine 34,100 Poultry: Layers 723,600 Broilers 38,160,000 Turkeys 7,710,000 1 2 2 3 Table JJ-2 to Subpart JJ of Part 98—Waste Characteristics Data Animal type Typical animal mass Volatile solids excretion rate Nitrogen excretion rate Maximum methane generation potential, B o 3 4 Dairy Cows 604 See Table JJ-3 See Table JJ-3 0.24 Dairy Heifers 476 See Table JJ-3 See Table JJ-3 0.17 Dairy Calves 118 6.41 0.30 0.17 Feedlot Steers 420 See Table JJ-3 See Table JJ-3 0.33 Feedlot heifers 420 See Table JJ-3 See Table JJ-3 0.33 Market Swine <60 lbs 16 8.80 0.60 0.48 Market Swine 60-119 lbs 41 5.40 0.42 0.48 Market Swine 120-179 lbs 68 5.40 0.42 0.48 Market Swine >180 lbs 91 5.40 0.42 0.48 Breeding Swine 198 2.60 0.24 0.48 Feedlot Sheep 25 9.20 0.42 0.36 Goats 64 9.50 0.45 0.17 Horses 450 10.00 0.30 0.33 Hens >/= 1 yr 1.8 10.09 0.83 0.39 Pullets 1.8 10.09 0.62 0.39 Other Chickens 1.8 10.80 0.83 0.39 Broilers 0.9 15.00 1.10 0.36 Turkeys 6.8 9.70 0.74 0.36 Table JJ-3 to Subpart JJ of Part 98—State-Specific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle State Volatile solids excretion rate (kg VS/day/1000 kg animal mass) Nitrogen excretion rate (kg VS/day/1000 kg animal mass) Dairy cows Dairy heifers Feedlot steer Feedlot heifers Dairy cows Dairy heifers Feedlot steer Feedlot heifers Alabama 8.40 8.35 4.27 4.74 0.50 0.46 0.36 0.38 Alaska 7.30 8.35 4.15 4.58 0.45 0.46 0.35 0.37 Arizona 10.37 8.35 3.91 4.27 0.58 0.46 0.33 0.34 Arkansas 7.59 8.35 3.98 4.35 0.46 0.46 0.33 0.35 California 10.02 8.35 3.96 4.33 0.56 0.46 0.33 0.34 Colorado 10.25 8.35 3.97 4.34 0.58 0.46 0.33 0.35 Connecticut 9.22 8.35 4.41 4.93 0.53 0.46 0.37 0.40 Delaware 8.63 8.35 4.19 4.64 0.51 0.46 0.35 0.37 Florida 8.90 8.35 4.15 4.58 0.52 0.46 0.35 0.37 Georgia 9.07 8.35 4.18 4.63 0.53 0.46 0.35 0.37 Hawaii 7.00 8.35 4.15 4.58 0.44 0.46 0.35 0.37 Idaho 10.11 8.35 4.03 4.42 0.57 0.46 0.34 0.35 Illinois 9.07 8.35 4.15 4.59 0.52 0.46 0.35 0.37 Indiana 9.38 8.35 3.98 4.35 0.54 0.46 0.33 0.35 Iowa 9.46 8.35 3.93 4.28 0.54 0.46 0.33 0.34 Kansas 9.63 8.35 3.97 4.35 0.55 0.46 0.33 0.35 Kentucky 7.89 8.35 4.20 4.65 0.48 0.46 0.35 0.37 Louisiana 7.39 8.35 4.07 4.48 0.45 0.46 0.34 0.36 Maine 8.99 8.35 4.07 4.47 0.52 0.46 0.34 0.36 Maryland 9.02 8.35 4.05 4.45 0.52 0.46 0.34 0.35 Massachusetts 8.63 8.35 4.15 4.58 0.51 0.46 0.35 0.37 Michigan 10.05 8.35 4.00 4.38 0.57 0.46 0.34 0.35 Minnesota 9.17 8.35 3.89 4.24 0.53 0.46 0.33 0.34 Mississippi 8.19 8.35 4.14 4.57 0.49 0.46 0.35 0.37 Missouri 8.02 8.35 4.08 4.49 0.48 0.46 0.34 0.36 Montana 9.03 8.35 4.23 4.69 0.52 0.46 0.36 0.38 Nebraska 9.09 8.35 3.98 4.35 0.53 0.46 0.33 0.35 Nevada 9.65 8.35 4.07 4.48 0.55 0.46 0.34 0.36 New Hampshire 9.44 8.35 3.94 4.30 0.54 0.46 0.33 0.34 New Jersey 8.51 8.35 3.98 4.36 0.50 0.46 0.33 0.35 New Mexico 10.34 8.35 3.88 4.22 0.58 0.46 0.32 0.33 New York 9.42 8.35 3.75 4.05 0.54 0.46 0.31 0.32 North Carolina 9.38 8.35 4.20 4.65 0.55 0.46 0.35 0.37 North Dakota 8.40 8.35 3.88 4.22 0.50 0.46 0.32 0.34 Ohio 9.01 8.35 3.96 4.33 0.52 0.46 0.33 0.34 Oklahoma 8.58 8.35 3.98 4.35 0.50 0.46 0.33 0.35 Oregon 9.40 8.35 4.06 4.46 0.54 0.46 0.34 0.36 Pennsylvania 9.26 8.35 3.98 4.35 0.53 0.46 0.33 0.35 Rhode Island 8.94 8.35 4.36 4.87 0.52 0.46 0.37 0.39 South Carolina 9.05 8.35 4.15 4.58 0.53 0.46 0.35 0.37 South Dakota 9.45 8.35 4.01 4.39 0.54 0.46 0.34 0.35 Tennessee 8.60 8.35 4.48 5.02 0.51 0.46 0.38 0.40 Texas 9.51 8.35 3.95 4.32 0.54 0.46 0.33 0.34 Utah 9.70 8.35 3.88 4.22 0.55 0.46 0.32 0.34 Vermont 9.03 8.35 4.10 4.52 0.52 0.46 0.34 0.36 Virginia 9.02 8.35 3.98 4.35 0.53 0.46 0.33 0.35 Washington 10.36 8.35 4.07 4.47 0.58 0.46 0.34 0.36 West Virginia 8.13 8.35 4.65 5.25 0.48 0.46 0.40 0.42 Wisconsin 9.34 8.35 3.95 4.31 0.54 0.46 0.33 0.34 Wyoming 9.29 8.35 4.17 4.61 0.53 0.46 0.35 0.37 Table JJ-4 to Subpart JJ of Part 98—Volatile Solids and Nitrogen Removal through Solids Separation Type of solids separation Volatile solids removal (decimal) Nitrogen removal (decimal) Gravity 0.60 0.60 Mechanical: Stationary Screen 0.20 0.10 Vibrating Screen 0.15 0.15 Screw Press 0.25 0.15 Centrifuge 0.50 0.25 Roller drum 0.25 0.15 Belt press/screen 0.50 0.30 Table JJ-6 to Subpart JJ of Part 98—Collection Efficiencies of Anaerobic Digesters Anaerobic digester type Cover type Methane collection efficiency Covered anaerobic lagoon (biogas capture) Bank to bank, impermeable 0.975 Modular, impermeable 0.70 Complete mix, fixed film, or plug flow digester Enclosed Vessel 0.99 Table JJ-7 to Subpart JJ of Part 98—Nitrous Oxide Emission Factors (kg N 2 Manure management system component N 2 Uncovered anaerobic lagoon 0 Liquid/Slurry (with crust cover) 0.005 Liquid/Slurry (without crust cover) 0 Storage pits 0.002 Digesters 0 Solid manure storage 0.005 Dry lots (including feedlots) 0.02 High-rise house for poultry (poultry without litter) 0.001 Poultry production with litter 0.001 Deep bedding for cattle and swine (active mix) 0.07 Deep bedding for cattle and swine (no mix) 0.01 Manure Composting (in vessel) 0.006 Manure Composting (intensive) 0.1 Manure Composting (passive) 0.01 Manure Composting (static) 0.006 Aerobic Treatment (forced aeration) 0.005 Aerobic Treatment (natural aeration) 0.01 Subpart KK [Reserved] Subpart LL—Suppliers of Coal-based Liquid Fuels § 98.380 Definition of the source category. This source category consists of producers, importers, and exporters of products listed in Table MM-1 of subpart MM that are coal-based (coal-to-liquid products). (a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in converting coal into liquid products using a process involving conversion of coal into gas and then into liquids (e.g., Fischer-Tropsch) or conversion of coal directly into liquids (i.e., direct liquefaction). (b) An importer or exporter shall have the same meaning given in § 98.6. § 98.381 Reporting threshold. Any supplier of coal-to-liquid products who meets the requirements of § 98.2(a)(4) must report GHG emissions. § 98.382 GHGs to report. Suppliers of coal-based liquid fuels must report the CO 2 2 [81 FR 89267, Dec. 9, 2016] § 98.383 Calculating GHG emissions. Suppliers of coal-based liquid fuels must follow the calculation methods of § 98.393 as if they applied to the appropriate coal-to-liquid product supplier ( i.e., (a) In calculation methods in § 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products. (b) In calculation methods in § 98.393 for non-crude feedstocks or non-crude petroleum feedstocks, producers of coal-to-liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on site. (c) In calculation methods in § 98.393 for petroleum feedstocks, suppliers of coal-to-liquid products shall also include coal and coal-to-liquid products that enter the facility to be further processed or otherwise used on site. [81 FR 89267, Dec. 9, 2016] § 98.384 Monitoring and QA/QC requirements. Suppliers of coal-based liquid fuels must follow the monitoring and QA/QC requirements in § 98.394 as if they applied to the appropriate coal-to-liquid product supplier. Any monitoring and QA/QC requirement for petroleum products in § 98.394 also applies to coal-to-liquid products. [81 FR 89267, Dec. 9, 2016] § 98.385 Procedures for estimating missing data. Suppliers of coal-based liquid fuels must follow the procedures for estimating missing data in § 98.395 as if they applied to the appropriate coal-to-liquid product supplier. Any procedure for estimating missing data for petroleum products in § 98.395 also applies to coal-to-liquid products. [81 FR 89267, Dec. 9, 2016] § 98.386 Data reporting requirements. In addition to the information required by § 98.3(c), the following requirements apply: (a) Producers shall report the following information for each coal-to-liquid facility: (1) [Reserved] (2) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product). (4)-(5) [Reserved] (6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(2), shall not be reported under this paragraph. (7) For each product reported in paragraph (a)(6) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product). (8) [Reserved] (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (11) For every product reported in paragraph (a)(6) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Method 2 of subpart MM of this part was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (13) [Reserved] (14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels. (15) [Reserved] (16) The CO 2 (17) The CO 2 (18) Annual CO 2 (19) Annual CO 2 (20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in paragraph (a)(2) of this section. (b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level: (1) [Reserved] (2) For each product listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of subpart MM of this part. (3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product). (4) [Reserved] (5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c) (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 (8) The total sum of CO 2 (c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level: (1) [Reserved] (2) For each product listed in table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product). (4) [Reserved] (5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 (8) Total sum of CO 2 (d) Blended feedstock and products. (i) Volume or mass of each blending component. (ii) The CO 2 (iii) Whether it is a blended feedstock or a blended product. (2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock. (3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66475, Oct. 28, 2010; 78 FR 71972, Nov. 29, 2013; 81 FR 89267, Dec. 9, 2016] § 98.387 Records that must be retained. Suppliers of coal-based liquid fuels must retain records according to the requirements in § 98.397 as if they applied to the appropriate coal-to-liquid product supplier ( e.g., [81 FR 89268, Dec. 9, 2016] § 98.388 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart MM—Suppliers of Petroleum Products § 98.390 Definition of the source category. This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM-1 of this subpart. (a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil. (b) A refiner is the owner or operator of a petroleum refinery. (c) Importer has the same meaning given in § 98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition. (d) Exporter has the same meaning given in § 98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition. § 98.391 Reporting threshold. Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions. § 98.392 GHGs To report. Suppliers of petroleum products must report the CO 2 2 § 98.393 Calculating GHG emissions. (a) Calculation for individual products produced, imported, or exported. 2 Where: CO 2i 2 Product i EF i 2 2 (2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO 2 Where: CO 2i 2 Product i EF i 2 2 (b) Calculation for individual products that enter a refinery as a non-crude feedstock. 2 Where: CO 2j 2 Feedstock j EF j 2 2 (2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO 2 Where: CO 2j 2 Feedstock j EF j 2 2 (c) Calculation for biomass co-processed with petroleum feedstocks. 2 Where: CO 2m 2 Biomass m EF m 2 2 (2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate CO 2 Where: CO 2m 2 Biomass m EF m 2 2 (d) Summary calculation for refinery products. 2 Where: CO 2r 2 CO 2i 2 CO 2j 2 CO 2m 2 (e) Summary calculation for importer and exporter products. 2 Where: CO 2x 2 CO 2i 2 (f) Emission factors for petroleum products and natural gas liquids. i,j (1) Calculation Method 1. i 2 (2) Calculation Method 2. Where: EF i,j 2 Density = Density of the petroleum product or natural gas liquid (metric tons per barrel for non-solid products, 1 for solid products). Carbon share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation). 44/12 = Conversion factor for carbon to carbon dioxide. (ii) If you use a standard method that involves gas chromatography to determine the percent mass of each component in a product, calculate the product's carbon share using Equation MM-7 of this section. Where: Carbon Share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid. %Composition i* * *n = Percent of total mass that each molecular component in the petroleum product or natural gas liquid represents as determined by the procedures in the selected standard method. %Mass i* * *n (g) Emission factors for biomass co-processed with petroleum feedstocks. 2 m 2 (h) Special procedures for blended biomass-based fuels. (1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO 2 Where: CO 2i 2 Product i EF i 2 2 %Vol i (2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO 2 Where: CO 2j 2 Feedstock j EF j 2 2 %Vol j (3) Calculation Method 2 procedures for products. 2 where: CO 2i 2 Product i EF i 2 2 EF m 2 %Vol m (ii) In the event that a petroleum product contains denatured ethanol, importers and exporters must follow Calculation Method 1 procedures in paragraph (h)(1) of this section; and refineries must sample the petroleum portion of the blended biomass-based fuel prior to blending and calculate CO 2 where: CO 2i 2 Product p EF i 2 2 (4) Calculation Method 2 procedures for non-crude feedstocks. 2 where: CO 2j 2 Feedstock j EF j 2 2 EF m 2 %Vol m (ii) In the event that a non-crude feedstock contains denatured ethanol, refiners must follow Calculation Method 1 procedures in paragraph (h)(2) of this section. (i) Optional procedures for blended products that do not contain biomass. (i) The reporter knows the relative proportion of each component of the blend (i.e., the mass or volume percentage). (ii) Each component of blended product “i” or blended non-crude feedstock “j” meets the strict definition of a product listed in Table MM-1 to subpart MM. (iii) The blended product or non-crude feedstock is not comprised entirely of natural gas liquids. (iv) The reporter uses Calculation Method 1. (v) Solid components are blended only with other solid components. (2) The reporter must calculate emissions for the blended product using Equation MM-12 of this section in place of Equation MM-1 of this section. where: CO 2i 2 Blending Component i...n EF i...n 2 2 n = Number of blending components blended into blended product “i”. (3) For refineries, the reporter must calculate emissions for the blended non-crude feedstock using Equation MM-13 of this section in place of Equation MM-2 of this section. where: CO 2i 2 Blending Component i...n EF i...n 2 2 n = Number of blending components blended into blended non-crude feedstock “j”. (4) For refineries, if a blending component “k” used in paragraph (i)(2) of this section enters the refinery before blending as non-crude feedstock: (i) The emissions that would result from the complete combustion or oxidation of non-crude feedstock “k” must still be calculated separately using Equation MM-2 of this section and applied in Equation MM-4 of this section. (ii) The quantity of blending component “k” applied in Equation MM-12 of this section and the quantity of non-crude feedstock “k” applied in Equation MM-2 of this section must be determined using the same method or practice. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66475, Oct. 28, 2010; 78 FR 71973, Nov. 29, 2013] § 98.394 Monitoring and QA/QC requirements. (a) Determination of quantity. (i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed. (iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, all measurements of quantity shall be temperature-adjusted and pressure-adjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices. (2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section. (3) The annual quantity of crude oil received shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice. (b) Equipment Calibration. (2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer's directions. (3) For units and processes that operate continuously with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under § 98.3(g)(5). (c) Procedures for Calculation Method 2 of this subpart. (2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization. (3) Density measurement. (i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus-based standards organization. (ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample. (iii) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization. (iv) All measurements of density shall be temperature-adjusted and pressure-adjusted to the conditions assumed for determining the quantities of the product reported under this subpart. (4) Carbon share measurement. (i) Reporters shall test for carbon share using an appropriate standard method published by a consensus-based standards organization. (ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided in the standard method and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements. (iii) The carbon share value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample. (iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66477, Oct. 28, 2010; 78 FR 71972, Nov. 29, 2013] § 98.395 Procedures for estimating missing data. (a) Determination of quantity. (1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter's established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product. (2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter's established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product. (b) Determination of emission factor. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71973, Nov. 29, 2013; 81 FR 89268, Dec. 9, 2016] § 98.396 Data reporting requirements. In addition to the information required by § 98.3(c), the following requirements apply: (a) Refiners shall report the following information for each facility: (1) [Reserved] (2) For each petroleum product or natural gas liquid listed in Table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product). (4)-(5) [Reserved] (6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this paragraph. (7) For each product reported in paragraph (a)(6) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product). (8) [Reserved] (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c) (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (13) [Reserved] (14) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels. (15) [Reserved] (16) The CO 2 (17) The CO 2 (18) The CO 2 (19) The sum of CO 2 (20) For all crude oil that enters the refinery, report the annual quantity in barrels. (21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section. (22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir. (b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level: (1) [Reserved] (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each product reported in paragraph (b)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product). (4) [Reserved] (5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percent mass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 (8) The sum of CO 2 (c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level: (1) [Reserved] (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. (3) For each product reported in paragraph (c)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is petroleum based (excluding any denaturant that may be present in any ethanol product). (4) [Reserved] (5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report: (i) The number of samples collected according to § 98.394(c). (ii) The sampling standard method used. (iii) The carbon share test results in percentmass. (iv) The standard method used to test carbon share. (v) The calculated CO 2 2 (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report: (i) The density test results in metric tons per barrel. (ii) The standard method used to test density. (7) The CO 2 (8) The sum of CO 2 (d) Blended non-crude feedstock and products. (i) Volume or mass of each blending component. (ii) The CO 2 (iii) Whether it is a blended non-crude feedstock or a blended product. (2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock. (3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66477, Oct. 28, 2010; 78 FR 71973, Nov. 29, 2013] § 98.397 Records that must be retained. (a) All reporters shall retain copies of all reports submitted to EPA under § 98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products. (b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used. (c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO 2 (d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO 2 (e) Estimates of missing data shall be documented and records maintained showing the calculations. (f) Reporters described in this subpart shall also retain all records described in § 98.3(g). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66478, Oct. 28, 2010; 78 FR 71974, Nov. 29, 2013] § 98.398 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Bulk NGLs Natural Gas Liquids (NGLs) [75 FR 66478, Oct. 28, 2010, as amended at 78 FR 71974, Nov. 29, 2013] Table MM-1 to Subpart MM of Part 98—Default Factors for Petroleum Products and Natural Gas Liquids 1 2 Products Column A: density Column B: Column C: 2 Finished Motor Gasoline Conventional—Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 Conventional—Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705 Reformulated—Summer Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 Reformulated—Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Gasoline—Other 0.1185 86.61 0.3763 Blendstocks CBOB—Summer Regular 0.1181 86.66 0.3753 Midgrade 0.1183 86.63 0.3758 Premium 0.1185 86.61 0.3763 CBOB—Winter Regular 0.1155 86.50 0.3663 Midgrade 0.1161 86.55 0.3684 Premium 0.1167 86.59 0.3705 RBOB—Summer Regular 0.1167 86.13 0.3686 Midgrade 0.1165 86.07 0.3677 Premium 0.1164 86.00 0.3670 RBOB—Winter Regular 0.1165 86.05 0.3676 Midgrade 0.1165 86.06 0.3676 Premium 0.1166 86.06 0.3679 Blendstocks—Other 0.1185 86.61 0.3763 Oxygenates Methanol 0.1268 37.48 0.1743 GTBA 0.1257 64.82 0.2988 MTBE 0.1181 68.13 0.2950 ETBE 0.1182 70.53 0.3057 TAME 0.1229 70.53 0.3178 DIPE 0.1156 70.53 0.2990 Distillate Fuel Oil Distillate No. 1 Ultra Low Sulfur 0.1346 86.40 0.4264 Low Sulfur 0.1346 86.40 0.4264 High Sulfur 0.1346 86.40 0.4264 Distillate No. 2 Ultra Low Sulfur 0.1342 87.30 0.4296 Low Sulfur 0.1342 87.30 0.4296 High Sulfur 0.1342 87.30 0.4296 Distillate Fuel Oil No. 4 0.1452 86.47 0.4604 Residual Fuel Oil No. 5 (Navy Special) 0.1365 85.67 0.4288 Residual Fuel Oil No. 6 (a.k.a. Bunker C) 0.1528 84.67 0.4744 Kerosene-Type Jet Fuel 0.1294 86.30 0.4095 Kerosene 0.1346 86.40 0.4264 Diesel—Other 0.1452 86.47 0.4604 Petrochemical Feedstocks Naphthas (<401 °F) 0.1158 84.11 0.3571 Other Oils (>401 °F) 0.1390 87.30 0.4450 Unfinished Oils Heavy Gas Oils 0.1476 85.80 0.4643 Residuum 0.1622 85.70 0.5097 Other Petroleum Products and Natural Gas Liquids Aviation Gasoline 0.1120 85.00 0.3490 Special Naphthas 0.1222 84.76 0.3798 Lubricants 0.1428 85.80 0.4492 Waxes 0.1285 85.30 0.4019 Petroleum Coke 0.1818 92.28 0.6151 Asphalt and Road Oil 0.1634 83.47 0.5001 Still Gas 0.1405 77.70 0.4003 Ethane 3 0.0579 79.89 0.170 Ethylene 4 0.0492 85.63 0.154 Propane 3 0.0806 81.71 0.241 Propylene 3 0.0827 85.63 0.260 Butane 3 0.0928 82.66 0.281 Butylene 3 0.0972 85.63 0.305 Isobutane 3 0.0892 82.66 0.270 Isobutylene 3 0.0949 85.63 0.298 Isobutylene 0.0936 85.63 0.2939 Pentanes Plus 0.1055 83.63 0.3235 Miscellaneous Products 0.1380 85.49 0.4326 1 2 3 4 [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71975, Nov. 29, 2013] Table MM-2 to Subpart MM of Part 98—Default Factors for Biomass-Based Fuels and Biomass Biomass-based fuel and biomass Column A: Column B: Carbon share Column C: 2 Ethanol (100%) 0.1267 52.14 0.2422 Biodiesel (100%, methyl ester) 0.1396 77.30 0.3957 Rendered Animal Fat 0.1333 76.19 0.3724 Vegetable Oil 0.1460 76.77 0.4110 Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids § 98.400 Definition of the source category. This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies. (a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their constituent liquid products or mixtures of products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities. (b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are within a single state that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet. (c) This supply category does not consist of the following facilities: (1) Field gathering and boosting stations. (2) Natural gas processing plants that separate NGLs from natural gas and produce bulk or y-grade NGLs but do not fractionate these NGLs into their constituent products. (3) Facilities that meet the definition of refineries and report under subpart MM of this part. (4) Facilities that meet the definition of petrochemical plants and report under subpart X of this part. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71975, Nov. 29, 2013] § 98.401 Reporting threshold. Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions associated with the products they supply. [81 FR 89268, Dec. 9, 2016] § 98.402 GHGs to report. (a) NGL fractionators must report the CO 2 (b) LDCs must report the CO 2 § 98.403 Calculating GHG emissions. (a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO 2 (1) Calculation Methodology 1. 2 h e.g., 2 2 2 Where: CO 2i 2 Fuel h HHV h EF h 2 2 1 × 10 −3 (2) Calculation Methodology 2. 2 h e.g., 2 2 2 Where: CO 2i 2 Fuel h EF h 2 2 2 (b) Each LDC shall follow the procedures below. (1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use Equation NN-3 of this section and the default values for the CO 2 2 Where: CO 2j 2 Fuel = Total annual volume of natural gas supplied to downstream gas transmission pipelines and other local distribution companies (Mscf per year). EF = Fuel-specific CO 2 2 (2)(i) For natural gas delivered to large end-users, use Equation NN-4 of this section and the default values for the CO 2 (ii) Alternatively, reporter-specific CO 2 Where: CO 2k 2 Fuel = Total annual volume of natural gas supplied to each large end-user k, as defined in paragraph (b)(2)(i) of this section (Mscf per year). EF = Fuel-specific CO 2 2 (3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN-5a of this section. For natural gas that is received by means other than through the city gate, and is not otherwise accounted for by Equation NN-1 or NN-2 of this section, use Equation NN-5b of this section. (i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied and stored, and for gas removed from storage and used for deliveries, use Equation NN-5a of this section and the default value for the CO 2 2 Where: CO 2l 2 Fuel 1 Fuel 2 EF = CO 2 2 (ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN-5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate. Use the default value for the CO 2 2 Where: CO 2n 2 Fuel z EF z 2 2 (4) Calculate the total CO 2 Where: CO 2 2 CO 2i 2 CO 2j 2 CO 2k 2 CO 2l 2 CO 2n 2 (c) Each NGL fractionator shall follow the following procedures. (1)(i) For fractionated NGLs received by the reporter from other NGL fractionators, you shall use Equation NN-7 of this section and the default values for the CO 2 (ii) Alternatively, reporter-specific CO 2 Where: CO 2m 2 Fuel g EF g 2 2 (2) Calculate the total CO 2 Where: CO 2 2 CO 2i 2 CO 2m 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66478, Oct. 28, 2010; 78 FR 71975, Nov. 29, 2013; 81 FR 89268, Dec. 9, 2016] § 98.404 Monitoring and QA/QC requirements. (a) Determination of quantity. (i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed. (2) NGL fractionators and LDCs shall base the minimum frequency of the product quantity measurements, to be summed to the annual quantity reported, on the reporter's standard practices for commercial operations. (i) For NGL fractionators the minimum frequency of measurements shall be the measurements taken at custody transfers summed to the annual reportable volume. (ii) For natural gas the minimum frequency of measurement shall be based on the LDC's standard measurement schedules used for billing purposes and summed to the annual reportable volume. (3) NGL fractionators shall use measurement for NGLs at custody transfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility. (4) If a NGL fractionator supplies a product that is a mixture or blend of two or more products listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator shall report the quantities of the constituents of the mixtures or blends separately. (5) For an LDC using Equation NN-1 or NN-2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s). (i) If the LDC makes its own quantity measurements according to established business practices, its own measurements shall be used. (ii) If the LDC does not make its own quantity measurements according to established business practices, it shall use its delivering pipeline invoiced measurements for natural gas deliveries to the LDC city gate, used in determining daily system sendout. (6) An LDC using Equation NN-3 of this subpart shall measure natural gas at the custody transfer meters. (7) An LDC using Equation NN-4 of this subpart shall measure natural gas at the large end-user's meter(s). Where a large end-user is known to have more than one meter located at their facility, based on readily available information in the LDCs possession, the reporter shall measure the natural gas at each meter and sum the annual volume delivered to all meters located at the end-user's facility to determine the total volume delivered to the large end-user. Otherwise, the reporter shall consider the total annual volume delivered through each single meter at a single particular location to be the volume delivered to an individual large end-user. (8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall measure natural gas as follows: (i) Fuel 1 (ii) Fuel 2 (iii) Fuel z (9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of one atmosphere. (b) Determination of higher heating values (HHV). (2) When a reporter uses a reporter-specific HHV to calculate Equation NN-1 of this subpart, an appropriate standard test published by a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA. (i) If an LDC makes its own HHV measurements according to established business practices, then its own measurements shall be used. (ii) If an LDC does not make its own measurements according to established business practices, it shall use its delivering pipeline measurements. (c) Determination of emission factor (EF). (2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-5a, NN-5b, or NN-7 of this subpart, the appropriate value shall be taken from Table NN-2 of this subpart. (3) When a reporter uses a reporter-specific EF, the reporter shall use an appropriate standard method published by a consensus-based standards organization to conduct compositional analysis necessary to determine reporter-specific CO 2 (d) Equipment Calibration. (2) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a, and NN-5b of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions. (3) Equipment used to measure quantities in Equations NN-3 and NN-4 of this subpart shall be recalibrated at the frequency commonly used within the industry. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71976, Nov. 29, 2013; 81 FR 89269, Dec. 9, 2016] § 98.405 Procedures for estimating missing data. (a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section. (b) Determination of quantity. (2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of actual deliveries are not available. (c) Determination of HHV and EF. (2) Whenever an LDC that does not make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use the default HHV provided in Table NN-1 of this part for that period. (3) [Reserved] (4) Whenever a reporter cannot follow the quality assurance procedures for developing a reporter-specific EF, as specified in § 98.404, during any period for any reason, the reporter shall use the default EF provided in § 98.408 for that period. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71977, Nov. 29, 2013] § 98.406 Data reporting requirements. (a) In addition to the information required by § 98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following information. (1) Annual quantity (in barrels) of each NGL product supplied (including fractionated NGL products received from other NGL fractionators) in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel h (2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel g (3) Annual volumes in Mscf of natural gas received for processing. (4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs: (i) Received. (ii) Supplied to downstream users. (5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others. (6) Annual CO 2 (7) Annual CO 2 (8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section. (9) If the NGL fractionator developed reporter-specific EFs or HHVs, report the following for each product type: (i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404(b)(2) and (c)(3). (ii) The developed HHV(s). (iii) The developed EF(s). (b) In addition to the information required by § 98.3(c), the annual report for each LDC shall contain the following information. (1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC's distribution system, including for use by the LDC (Fuel h (2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored (Fuel 1 (3) Annual volume in Mscf of natural gas withdrawn from on-system storage and annual volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage for delivery on the distribution system (Fuel 2 (4) [Reserved] (5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied through the LDC distribution system. This includes natural gas from producers and natural gas processing plants from local production, or natural gas that was vaporized upon receipt and delivered, and any other source that bypassed the city gate (Fuel z (6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies (Fuel in Equation NN-3 of this subpart). (7) Annual volume in Mscf of natural gas delivered by the LDC to each large end-user as defined in § 98.403(b)(2)(i) of this section. (8) The total annual CO 2 (9) Annual CO 2 (10) The specific industry standard used to develop the volume reported in paragraph (b)(1) of this section. (11) If the LDC developed reporter-specific EFs or HHVs, report the following: (i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404 (b)(2) and (c)(3). (ii) The developed HHV(s). (iii) The developed EF(s). (12) For each large end-user reported in paragraph (b)(7) of this section, report: (i) The customer name, address, and meter number(s). (ii) Whether the quantity of natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to a large end-user's facility, or the quantity delivered to a specific meter located at the facility. (iii) If known, report the EIA identification number of each LDC customer. (13) The annual volume in Mscf of natural gas delivered by the LDC (including natural gas that is not owned by the LDC) to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & Disposition) and Instructions. (i) Residential consumers. (ii) Commercial consumers. (iii) Industrial consumers. (iv) Electricity generating facilities. (14) The name of the U.S. state or territory covered in this report submission. (c) Each reporter shall report the number of days in the reporting year for which substitute data procedures were used for the following purpose: (1) To measure quantity. (2) To develop HHV(s). (3) To develop EF(s). [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66479, Oct. 28, 2010; 78 FR 71977, Nov. 29, 2013; 81 FR 89269, Dec. 9, 2016] § 98.407 Records that must be retained. In addition to the information required by § 98.3(g), the reporter shall retain the following records: (a) Records of all meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part. (b) Records documenting any estimates of missing metered data and showing the calculations of the values used for the missing data. (c) Calculations and worksheets used to estimate CO 2 (d) Records related to the large end-users identified in § 98.406(b)(7). (e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating values and emission factors. (f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to customers or on behalf of customers. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66479, Oct. 28, 2010] § 98.408 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table NN-1 to Subpart NN of Part 98—Default Factors for Calculation Methodology 1 of This Subpart Fuel Default higher heating value 1 Default CO2 Natural Gas 1.026 MMBtu/Mscf 53.06 Propane 3.84 MMBtu/bbl 62.87 Normal butane 4.34 MMBtu/bbl 64.77 Ethane 2.85 MMBtu/bbl 59.60 Isobutane 4.16 MMBtu/bbl 64.94 Pentanes plus 4.62 MMBtu/bbl 70.02 1 [78 FR 71977, Nov. 29, 2013] Table NN-2 to Subpart NN of Part 98—Default Factors for Calculation Methodology 2 of This Subpart Fuel Unit Default CO2 emission factor 1 Natural Gas Mscf 0.0544 Propane Barrel 0.241 Normal butane Barrel 0.281 Ethane Barrel 0.170 Isobutane Barrel 0.270 Pentanes plus Barrel 0.324 1 [78 FR 71977, Nov. 29, 2013, as amended at 79 FR 3508, Jan. 22, 2014; 81 FR 89270, Dec. 9, 2016] Subpart OO—Suppliers of Industrial Greenhouse Gases § 98.410 Definition of the source category. (a) The industrial gas supplier source category consists of any facility that produces fluorinated GHGs or nitrous oxide; any bulk importer of fluorinated GHGs or nitrous oxide; and any bulk exporter of fluorinated GHGs or nitrous oxide. Starting with reporting year 2018, this source category also consists of any facility that produces fluorinated HTFs; any bulk importer of fluorinated HTFs; any bulk exporter of fluorinated HTFs; and any facility that destroys fluorinated GHGs or fluorinated HTFs. (b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG includes the manufacture of a fluorinated GHG as an isolated intermediate for use in a process that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG also includes the creation of a fluorinated GHG (with the exception of HFC-23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG, 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 at § 98.414(a). (c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH 4 3 (d) To produce a fluorinated HTF means to manufacture, from any raw material or feedstock chemical, a fluorinated GHG used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in processes including but not limited to certain types of electronics manufacturing production processes. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants. For fluorinated heat transfer fluids under this subpart, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of fluorinated greenhouse gas in § 98.6 shall not apply. Fluorinated heat transfer fluids include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. Producing a fluorinated HTF does not include the reuse or recycling of a fluorinated HTF, the creation of intermediates, or the creation of fluorinated HTFs that are released or destroyed at the production facility before the production measurement at § 98.414(a). (e) For purposes of this subpart, to destroy fluorinated GHGs or fluorinated HTFs means to cause the expiration of a previously produced (as defined in paragraphs (b) and (d) of this section) fluorinated GHG or fluorinated HTF to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. For purposes of this subpart, such destruction does not include HFC-23 destruction as defined at § 98.150 or the dissociation of fluorinated GHGs that occurs during electronics manufacturing as defined at § 98.90. For example, such destruction does not include the dissociation of fluorinated GHGs that occurs during etch or chamber cleaning processes or during use of abatement systems that treat the fluorinated GHGs vented from such processes at electronics manufacturing facilities. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010; 81 FR 89270, Dec. 9, 2016] § 98.411 Reporting threshold. Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions. § 98.412 GHGs to report. You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year. Starting with reporting year 2018, you must also report the emissions that would result from the release of each fluorinated HTF that is not also a fluorinated GHG and that you produce, import, export, transform, or destroy during the calendar year. [81 FR 89270, Dec. 9, 2016] § 98.413 Calculating GHG emissions. (a) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO-1 of this section: P = Mass of fluorinated GHG, fluorinated HTF, or nitrous oxide produced annually. P p (b) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced over the period “p” by using Equation OO-2 of this section: Where: P p O p U p (c) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF transformed by using Equation OO-3 of this section: Where: T = Mass of fluorinated GHG, fluorinated HTF, or nitrous oxide transformed annually (metric tons). F T E T (d) Calculate the total mass of each fluorinated GHG or fluorinated HTF destroyed by using Equation OO-4 of this section: Where: D = Mass of fluorinated GHG or fluorinated HTF destroyed annually (metric tons). F D DE = Destruction efficiency of the destruction device (fraction). [74 FR 56374, Oct. 30, 2009, as amended at 81 FR 89270, Dec. 9, 2016] § 98.414 Monitoring and QA/QC requirements. (a) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG or fluorinated HTF, the concentrations of each of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG or fluorinated HTF, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG or fluorinated HTF coming out of the production process. (b) The mass of any used fluorinated GHGs, fluorinated HTFs, or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs or fluorinated HTFs, the returned heels shall be considered used fluorinated GHGs or fluorinated HTFs for purposes of this paragraph (b) and § 98.413(b). (c) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. (d) The fraction of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs, fluorinated HTFs, or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted. (e) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. (f) The mass of fluorinated GHGs or fluorinated HTFs sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF, the concentration of the fluorinated GHG or fluorinated HTF shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF sent to another facility for destruction. (g) You must estimate the share of the mass of fluorinated GHGs or fluorinated HTFs in paragraph (f) of this section that is comprised of fluorinated GHGs or fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes. (h) You must measure the mass of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs or fluorinated HTFs 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 one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF being destroyed, you must estimate the concentrations of the fluorinated GHG or fluorinated HTF being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF fed into the destruction device. (i) Very small quantities of fluorinated GHGs or fluorinated HTFs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section. (j) [Reserved] (k) For purposes of Equation OO-4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device. (l) In their estimates of the mass of fluorinated GHGs or fluorinated HTFs destroyed, facilities that destroy fluorinated GHGs or fluorinated HTFs 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 oxidizer manufacturer specifications. (m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others). (n) If the mass coming out of the production process includes more than one fluorinated GHG or fluorinated HTF, you shall measure the concentrations of all of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, as follows: (1) Analytical Methods. (2) Documentation in GHG Monitoring Plan. (3) Frequency of measurement. (4) Measure all product grades. e.g., (5) Number of samples. (o) All analytical equipment used to determine the concentration of fluorinated GHGs or fluorinated HTFs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under paragraph (n) of this section and § 98.3(g)(5). Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed by a method specified in the GHG Monitoring Plan. (p) Isolated intermediates that are produced and transformed at the same facility are exempt from the monitoring requirements of this section. (q) Low-concentration constituents are exempt from the monitoring and QA/QC requirements of this section. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79167, Dec. 17, 2010; 81 FR 89270, Dec. 9, 2016] § 98.415 Procedures for estimating missing data. (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), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section. (b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall 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 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. § 98.416 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information: (a) Each fluorinated GHG, fluorinated HTF, or nitrous oxide production facility shall report the following information: (1) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction. (2) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF transformed at that facility, by process. (3) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(3) of this section 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. (4) [Reserved] (5) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF sent to another facility for transformation. (6) Total mass in metric tons of each fluorinated GHG or fluorinated HTF sent to another facility for destruction, except fluorinated GHGs and fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as byproducts or other wastes. Quantities to be reported under paragraph (a)(6) of this section could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction. (7) Total mass in metric tons of each fluorinated GHG or fluorinated HTF that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from the production process as a byproduct or other waste. (8)-(9) [Reserved] (10) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF fed into the transformation process, by process. (11) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(11) of this section 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. (12) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF that is measured coming out of the production process, by process. (13) Mass in metric tons of used nitrous oxide and of each used fluorinated GHG or fluorinated HTF added back into the production process ( e.g., (14) Names and addresses of facilities to which any nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sent to each for transformation. (15) Names and addresses of facilities to which any fluorinated GHGs or fluorinated HTFs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sent to each for destruction. (16) Where missing data have been estimated pursuant to § 98.415, 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. (b) Any facility or importer that destroys fluorinated GHGs or fluorinated HTFs shall submit a one-time report containing the information in paragraphs (b)(1) through (6) of this section for each destruction process by the applicable date set forth in paragraph (b)(7) of this section. Facilities and importers that previously submitted one-time reports under this paragraph for all destruction devices used to destroy fluorinated GHGs or fluorinated HTFs are exempt from this requirement unless they meet the conditions in paragraph (b)(6) of this section. (1) Destruction efficiency (DE). (2) Methods used to determine the destruction efficiency. (3) Methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed. (4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE. (5) Name of all applicable federal or state regulations that may apply to the destruction process. (6) If any process changes (including the acquisition of a new destruction device) affect unit destruction efficiency or the methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change. (7)(i) Any fluorinated GHG production facility or importer that destroys fluorinated GHGs must submit the one-time destruction report by March 31, 2011 or within 60 days of commencing fluorinated GHG destruction, whichever is later. (ii) Any fluorinated GHG production facility or importer that destroys fluorinated HTFs that are not also fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated HTF destruction, whichever is later. (iii) Any facility that destroys fluorinated GHGs or fluorinated HTFs but does not produce or import fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated GHG or fluorinated HTF destruction, whichever is later. (c) Each bulk importer of fluorinated GHGs, fluorinated heat transfer fluids (HTFs), or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except importers may exclude shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the importer also excludes transshipments from reporting of exports under paragraph (d) of this section; and heels that meet the conditions set forth at § 98.417(e) if the importer also excludes heels from any reporting of exports under paragraph (d) of this section. The report shall contain the following information for each import: (1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk, including each fluorinated GHG or fluorinated HTF constituent of the fluorinated GHG or fluorinated HTF product that makes up between 0.5 percent and 100 percent of the product by mass. (2) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical. (3) Date on which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported. (4) Port of entry through which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide passed. (5) Country from which the imported fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported. (6) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped. (7) Customs entry number and importer number for each shipment. (8) Total mass in metric tons of each fluorinated GHG or fluorinated HTF destroyed by the importer. (9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for transformation. (10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs or fluorinated HTFs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for destruction. (d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except reporters may exclude shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if the exporter also excludes transshipments from reporting of imports under paragraph (c) of this section; and heels if the exporter also excludes heels from any reporting of imports under paragraph (c) of this section. The report shall contain the following information for each export: (1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF exported in bulk. (2) Names and addresses of the exporter and the recipient of the exports. (3) Exporter's Employee Identification Number. (4) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped. (5) Date on which, and the port from which, the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported from the United States or its territories. (6) Country to which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported. (e) By March 31, 2011, or within 60 days of commencing fluorinated GHG production, whichever is later, a fluorinated GHG production facility shall submit a one-time report describing the following information: (1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision. (2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision. (3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate. (4) The method(s) by which the producer in practice estimates the masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the concentration of the fluorinated GHGs in the destroyed material, and the estimated precision and accuracy of this estimate. (5) The estimated percent efficiency of each production process for the fluorinated GHG produced. (f) By March 31, 2011, all fluorinated GHG production facilities shall submit a one-time report that includes the concentration of each fluorinated GHG constituent in each fluorinated GHG product as measured under § 98.414(n). If the facility commences production of a fluorinated GHG product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated GHG constituents of a fluorinated GHG product have changed, then the new or changed concentrations, as well as the date of the change, must be reflected in a revision to the report. The revised report must be submitted to EPA by the March 31st that immediately follows the measurement under § 98.414(n). (g) Isolated intermediates that are produced and transformed at the same facility are exempt from the reporting requirements of this section. (h) Low-concentration constituents are exempt from the reporting requirements of this section. (i) Each facility that destroys fluorinated GHGs or fluorinated HTFs but does not otherwise report under this section shall report the mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b) or (d), as applicable. Quantities to be reported under this paragraph (i) 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. (j) By March 31, 2019, all facilities that produce fluorinated HTFs that are not also fluorinated GHGs shall submit a one-time report that includes the concentration of each fluorinated HTF or fluorinated GHG constituent in each fluorinated HTF product as measured under § 98.414(n). If the facility commences production of a fluorinated HTF product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated HTF or fluorinated GHG constituents of a fluorinated HTF product have changed, then the new or changed concentrations, as well as the date of the change, must be provided in a revised report. The revised report must be submitted to EPA by the March 31st that immediately follows the new or repeat measurement under § 98.414(n). (k) For nitrous oxide, saturated perfluorocarbons, sulfur hexafluoride, and fluorinated heat transfer fluids as defined at § 98.6, report the end use(s) for which each GHG or fluorinated HTF is transferred and the aggregated annual quantity of that GHG or fluorinated HTF in metric tons that is transferred to that end use application, if known. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010; 76 FR 73905, Nov. 29, 2011; 81 FR 89272, Dec. 9, 2016; 89 FR 31942, Apr. 25, 2024] § 98.417 Records that must be retained. (a) In addition to the data required by § 98.3(g), the fluorinated GHG or fluorinated HTF production facility shall retain the following records: (1) Dated records of the data used to estimate the data reported under § 98.416. (2) Records documenting the initial and periodic calibration of the analytical equipment (including but not limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the manufacturer directions or industry standards used for calibration pursuant to § 98.414(m) and (o). (3) Dated records of the total mass in metric tons of each reactant fed into the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process. (4) Dated records of the total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process. (b) In addition to the data required by paragraph (a) of this section, any facility that destroys fluorinated GHGs or fluorinated HTFs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report in § 98.416(b). (c) In addition to the data required by § 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report: (1) A copy of the bill of lading for the import. (2) The invoice for the import. (3) The U.S. Customs entry form. (d) In addition to the data required by § 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report: (1) A copy of the bill of lading for the export and (2) The invoice for the export. (e) Every person who imports a container with a heel that is not reported under § 98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will: (1) Remain in the container and be included in a future shipment. (2) Be recovered and transformed. (3) Be recovered and destroyed. (4) Be recovered and included in a future shipment. (f) Isolated intermediates that are produced and transformed at the same facility are exempt from the recordkeeping requirements of this section. (g) Low-concentration constituents are exempt from the recordkeeping requirements of this section. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79168, Dec. 17, 2010; 76 FR 73905, Nov. 29, 2011; 81 FR 89273, Dec. 9, 2016] § 98.418 Definitions. Except as provided below, 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. Isolated intermediate Low-concentration constituent e.g., [75 FR 79169, Dec. 17, 2010, as amended at 81 FR 89273, Dec. 9, 2016] Subpart PP—Suppliers of Carbon Dioxide § 98.420 Definition of the source category. (a) The carbon dioxide (CO 2 (1) Facilities with production process units that capture a CO 2 2 2 2 (2) Facilities with CO 2 2 2 2 (3) Importers or exporters of bulk CO 2 (4) Facilities with process units, including but not limited to direct air capture (DAC), that capture a CO 2 2 2 (b) This source category is focused on upstream supply. It does not cover: (1) Storage of CO 2 (2) Use of CO 2 (3) Transportation or distribution of CO 2 (4) Purification, compression, or processing of CO 2 (5) On-site use of CO 2 (c) This source category does not include CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 89 FR 31943, Apr. 25, 2024] § 98.421 Reporting threshold. Any supplier of CO 2 2 § 98.422 GHGs to report. (a) Mass of CO 2 (b) Mass of CO 2 2 (c) Mass of CO 2 (d) Mass of CO 2 (e) Mass of CO 2 (1) Mass of CO 2 (2) Mass of CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79169, Dec. 17, 2010; 89 FR 31943, Apr. 25, 2024] § 98.423 Calculating CO 2 (a) Except as allowed in paragraph (b) of this section, calculate the annual mass of CO 2 2 (1) For each mass flow meter, you shall calculate quarterly the mass of CO 2 2 Where: CO 2,u 2 C CO 2 ,p,u 2 2 Q p,u p = Quarter of the year. u = Flow meter. (2) For each volumetric flow meter, you shall calculate quarterly the mass of CO 2 2 Where: CO 2,u 2 C CO2,p 2 2 2 Q p D p 2 2 CO2,p 2 2 CO2,p 2 p = Quarter of the year. u = Flow meter. (3) To aggregate data, use either Equation PP-3a or PP-3b in this paragraph, as appropriate. (i) For facilities with production process units, DAC process units, or production wells that capture or extract a CO 2 2 where: CO 2 2 CO 2,u 2 u = Flow meter. (ii) For facilities with production process units or DAC process units that capture a CO 2 2 where: CO 2 2 CO 2,u 2 CO 2,v 2 u = Main flow meter. v = Subsequent flow meter. (b) As an alternative to paragraphs (a)(1) through (3) of this section for CO 2 2 2 2 2 2 2 (1) For each CO 2 2 2 where: CO 2,u 2 2 C CO2,p,u 2 2 2 2 Q p,u 2 p = Quarter of the year. u = CO 2 (2) For each CO 2 2 where: CO 2,u 2 2 C CO2,p 2 2 2 2 2 Q p 2 D p 2 2 2 p 2 2 2,p 2 p = Quarter of the year. u = CO 2 (3) To aggregate data, sum the mass of CO 2 2 where: CO 2 2 2 CO 2,u 2 2 u = CO 2 (c) Importers or exporters that import or export CO 2 2 2 where: CO 2 2 Q = Annual mass in all CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79169, Dec. 17, 2010; 78 FR 71977, Nov. 29, 2013; 89 FR 31943, Apr. 25, 2024] § 98.424 Monitoring and QA/QC requirements. (a) Determination of quantity. (i) If the CO 2 (A) For reporters following the procedures in § 98.423(a)(3)(i), you must locate the flow meter(s) after the point of segregation. (B) For reporters following the procedures in paragraph (a)(3)(ii) of § 98.423, you must locate the main flow meter(s) on the captured CO 2 2 2 2 (ii) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO 2 (iii) Reporters that do not have a mass flow meter or volumetric flow meter installed to measure the flow of the CO 2 (2) Reporters following the procedures in paragraph (b) of § 98.423 shall determine quantity in accordance with this paragraph. (i) Reporters that supply CO 2 2 2 2 2 2 2 (ii) Reporters that supply CO 2 2 2 2 2 2 (3) Importers or exporters that import or export CO 2 2 (4) All flow meters, scales, and load cells used to measure quantities that are reported in § 98.423 of this subpart shall be operated and calibrated according to the following procedure: (i) You shall use an appropriate standard method published by a consensus-based standards organization if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices. (iii) You must ensure that any flow meter calibrations performed are NIST traceable. (5) Reporters using Equation PP-2 of this subpart and measuring CO 2 2 2 2 (i) You may use a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.aga.org http://www.asme.org http://www.api.org http://www.api.org (ii) You may follow an industry standard method. (b) Determination of concentration. 2 2 (2) Methods to measure the composition of the CO 2 2 see http://www.astm.org (c) You shall convert the density of the CO 2 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79170, Dec. 17, 2010] § 98.425 Procedures for estimating missing data. (a) Whenever the quality assurance procedures in § 98.424(a)(1) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO 2 (1) A quarterly CO 2 (2) A quarterly CO 2 (3) If a mass or volumetric flow meter is installed to measure the CO 2 2 (4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any period during which measurement equipment is inoperable. (b) Whenever the quality assurance procedures in § 98.424(b) cannot be followed to determine concentration of the CO 2 (1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year. (2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year. (3) The concentration used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any quarterly value. (c) Missing data on density of the CO 2 (d) Whenever the quality assurance procedures in § 98.424(a)(2) of this subpart cannot be followed to measure quarterly quantity of CO 2 (1) A quarterly quantity of CO 2 (2) A quarterly quantity of CO 2 (3) The quarterly quantity of CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79171, Dec. 17, 2010; 81 FR 89273, Dec. 9, 2016] § 98.426 Data reporting requirements. In addition to the information required by § 98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable: (a) If you use Equation PP-1 of this subpart, report the following information for each mass flow meter or CO 2 2 (1) Annual mass in metric tons of CO 2 (2) Quarterly mass in metric tons of CO 2 (3) Quarterly concentration of the CO 2 (4) The standard used to measure CO 2 (5) The location of the flow meter in your process chain in relation to the points of CO 2 (b) If you use Equation PP-2 of this subpart, report the following information for each volumetric flow meter or CO 2 2 (1) Annual mass in metric tons of CO 2 (2) Quarterly volume in standard cubic meters of CO 2 (3) Quarterly concentration of the CO 2 (4) Report density as follows: (i) Quarterly density of the CO 2 2 (ii) Quarterly density of CO 2 2 (5) The method used to measure density. (6) The standard used to measure CO 2 (7) The location of the flow meter in your process chain in relation to the points of CO 2 (c) For the aggregated annual mass of CO 2 (1) If you use Equation PP-3a of this subpart, report the annual CO 2 2 2 (2) If you use Equation PP-3b of this subpart, report: (i) The total annual CO 2 (ii) The total annual CO 2 (iii) The total annual CO 2 (iv) The location of each flow meter in relation to the point of segregation. (d) If you use Equation PP-4 of this subpart, report at the corporate level the annual mass of CO 2 2 (e) Each reporter shall report the following information: (1) The type of equipment used to measure the total flow of the CO 2 2 (2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section. (3) The number of days in the reporting year for which substitute data procedures were used for the following purpose: (i) To measure quantity. (ii) To measure concentration. (iii) To measure density. (f) Report the aggregated annual quantity of CO 2 (1) Food and beverage. (2) Industrial and municipal water/wastewater treatment. (3) Metal fabrication, including welding and cutting. (4) Greenhouse uses for plant growth. (5) Fumigants (e.g., grain storage) and herbicides. (6) Pulp and paper. (7) Cleaning and solvent use. (8) Fire fighting. (9) Transportation and storage of explosives. (10) Injection of carbon dioxide for enhanced oil and natural gas recovery that is covered by subpart UU of this part. (11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this part. (12) Geologic sequestration of carbon dioxide with enhanced oil recovery that is covered by subpart VV of this part. (13) Research and development. (14) Other. (g) Each production process unit that captures a CO 2 2 2 (h) If you capture a CO 2 2 (1) Report the facility identification number associated with the annual GHG report for the facility that is the source of the captured CO 2 (2) Report each facility identification number associated with the annual GHG reports for each subpart RR and subpart VV facility to which CO 2 (3) Report the annual quantity of CO 2 (i) If you capture a CO 2 2 i.e., 2 (1) Electricity excluding combined heat and power (CHP). (i) If the electricity is sourced from a grid connection, report the following information: (A) State where the facility with the DAC process unit is located. (B) County where the facility with the DAC process unit is located. (C) Name of the electric utility company that supplied the electricity as shown on the last monthly bill issued by the utility company during the reporting period. (D) Name of the electric utility company that delivered the electricity. In states with regulated electric utility markets, this will generally be the same utility reported under paragraph (i)(1)(i)(C) of this section, but in states with deregulated electric utility markets, this may be a different utility company. (E) Annual quantity of electricity consumed in MWh, calculated as the sum of the total energy usage values specified in all billing statements received during the reporting year. Most customers will receive 12 monthly billing statements during the reporting year. Many utilities bill their customers per kilowatt-hour (kWh); usage values on bills that are based on kWh should be divided by 1,000 to report the usage in MWh as required under this paragraph (i)(1)(i)(E). (ii) If electricity is sourced from on-site or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(1)(ii)(A) through (G) of this section, report the annual quantity of electricity consumed, in MWh. If the on-site electricity source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit. (A) Non-hydropower renewable sources including solar, wind, geothermal and tidal. (B) Hydropower. (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. (2) Heat excluding CHP. (i) Solar. (ii) Geothermal. (iii) Natural gas. (iv) Oil. (v) Coal. (vi) Nuclear. (vii) Other. (3) CHP—(i) Electricity from CHP. (A) Non-hydropower renewable sources including solar, wind, geothermal and tidal. (B) Hydropower. (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. (ii) Heat from CHP. (A) Solar. (B) Geothermal. (C) Natural gas. (D) Oil. (E) Coal. (F) Nuclear. (G) Other. [74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79171, Dec. 17, 2010; 78 FR 71977, Nov. 29, 2013; 80 FR 64660, Oct. 23, 2015; 89 FR 31943, Apr. 25, 2024] § 98.427 Records that must be retained. In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable. (a) The owner or operator of a facility containing production process units or DAC process units must retain quarterly records of captured or transferred CO 2 (b) The owner or operator of a CO 2 2 (c) Importers or exporters of CO 2 2 (d) Facilities subject to § 98.426(h) must retain records of CO 2 [74 FR 56374, Oct. 30, 2009, as amended at 80 FR 64660, Oct. 23, 2015; 89 FR 31944, Apr. 25, 2024] § 98.428 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart QQ—Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams Source: 75 FR 74856, Dec. 1, 2010, unless otherwise noted. § 98.430 Definition of the source category. (a) The source category, importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams, consists of any entity that imports or exports pre-charged equipment that contains a fluorinated GHG, and any entity that imports or exports closed-cell foams that contain a fluorinated GHG. § 98.431 Reporting threshold. Any importer or exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams who meets the requirements of § 98.2(a)(4) must report each fluorinated GHG contained in the imported or exported pre-charged equipment or closed-cell foams. § 98.432 GHGs to report. You must report the mass of each fluorinated GHG contained in pre-charged equipment or closed-cell foams that you import or export during the calendar year. For imports and exports of closed-cell foams where you do not know the identity and mass of the fluorinated GHG, you must report the mass of fluorinated GHG in CO 2 § 98.433 Calculating GHG contained in pre-charged equipment or closed-cell foams. (a) The total mass of each fluorinated GHG imported and exported inside equipment or foams must be estimated using Equation QQ-1 of this section: where: I = Total mass of the fluorinated GHG imported or exported annually (metric tons). t = Equipment/foam type containing the fluorinated GHG. S t N t 0.001 = Factor converting kg to metric tons. (b) When the identity and mass of fluorinated GHGs in a closed-cell foam is unknown to the importer or exporter, the total mass in CO 2 where: I = Total mass in CO 2 t = Equipment/foam type containing the fluorinated GHG. S t 2 2 2 N t 0.001 = Factor converting kg to metric tons. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013] § 98.434 Monitoring and QA/QC requirements. (a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to the year 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date or date of promulgation in § 98.3(d)(1) through (d)(2) means February 28, 2011. (b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013] § 98.435 Procedures for estimating missing data. Procedures for estimating missing data are not provided for importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams. A complete record of all measured parameters used in tracking fluorinated GHGs contained in pre-charged equipment or closed-cell foams is required. § 98.436 Data reporting requirements. (a) Each importer of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its imports at the corporate level, except for transshipments, as specified: (1) Total mass in metric tons of each fluorinated GHG imported in pre-charged equipment or closed-cell foams. (2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (holding charge, if applicable), and number imported. (3) For closed-cell foams that are imported inside of equipment, the identity of the fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. (4) For closed cell-foams that are not imported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity. (5) Dates on which the pre-charged equipment or closed-cell foams were imported. (6) If the importer does not know the identity and mass of the fluorinated GHGs within the closed-cell foam, the importer must report the following: (i) Total mass in metric tons of CO 2 (ii) For closed-cell foams that are imported inside of equipment, the mass of the fluorinated GHGs in CO 2 (iii) For closed-cell foams that are not imported inside of equipment, the density in CO 2 2 (iv) Dates on which the closed-cell foams were imported. (v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGs is unknown. (vi) Certification that the importer was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers. (7) The Harmonized tariff system (HTS) code for each type of pre-charged equipment or closed-cell foam imported. (b) Each exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its exports at the corporate level, except for transshipments, as specified: (1) Total mass in metric tons of each fluorinated GHG exported in pre-charged equipment or closed-cell foams. (2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (including holding charge, if applicable), and number exported. (3) For closed-cell foams that are exported inside of equipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams. (4) For closed-cell foams that are not exported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity. (5) Dates on which the pre-charged equipment or closed-cell foams were exported. (6) If the exporter does not know the identity and mass of the fluorinated GHG within the closed-cell foam, the exporter must report the following: (i) Total mass in metric tons of CO 2 (ii) For closed-cell foams that are exported inside of equipment, the mass of the fluorinated GHGs in CO 2 (iii) For closed-cell foams that are not exported inside of equipment, the density in CO 2 2 (iv) Dates on which the closed-cell foams were exported. (v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGg is unknown. (vi) Certification that the exporter was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers. (7) The Schedule B code for each type of pre-charged equipment or closed-cell foam exported. [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013; 89 FR 31944, Apr. 25, 2024] § 98.437 Records that must be retained. (a) In addition to the data required by § 98.3(g), importers of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the imports that they report: (1) A copy of the bill of lading for the import. (2) The invoice for the import. (3) The U.S. Customs entry form. (4) Ports of entry through which the pre-charged equipment or closed-cell foams passed. (5) Countries from which the pre-charged equipment or closed-cell foams were imported. (6) For importers that report the mass of fluorinated GHGs within closed-cell foams on a CO 2 (b) In addition to the data required by § 98.3(g), exporters of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the exports that they report: (1) A copy of the bill of lading for the export and (2) The invoice for the export. (3) Ports of exit through which the pre-charged equipment or closed-cell foams passed. (4) Countries to which the pre-charged equipment or closed-cell foams were exported. (5) For exporters that report the mass of fluorinated GHGs within closed-cell foams on a CO 2 (c) For importers and exports of fluorinated GHGs inside pre-charged equipment and closed-cell foams, the GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. (d) Persons who transship pre-charged equipment and closed-cell foams containing fluorinated GHGs must maintain records that indicated that the pre-charged equipment or foam originated in a foreign country and was destined for another foreign country and did not enter into commerce in the United States. § 98.438 Definitions. 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 must take precedence for the reporting requirements in this subpart. Appliance Closed-cell foam Electrical equipment Fluorinated GHG refrigerant Pre-charged appliance Pre-charged appliance component Pre-charged electrical equipment Pre-charged electrical equipment component Pre-charged equipment [74 FR 56374, Oct. 30, 2009, as amended at 78 FR 71978, Nov. 29, 2013] Subpart RR—Geologic Sequestration of Carbon Dioxide Source: 75 FR 75078, Dec. 1, 2010, unless otherwise noted. § 98.440 Definition of the source category. (a) The geologic sequestration of carbon dioxide (CO 2 2 (b) This source category includes all wells permitted as Class VI under the Underground Injection Control program. (c) This source category does not include a well or group of wells where a CO 2 (1) The owner or operator injects the CO 2 (2) The well is permitted as Class VI under the Underground Injection Control program. (d) Exemption for research and development projects. (1) Process for obtaining an exemption. (2) Content of submission. (i) The planned duration of CO 2 (ii) The planned annual CO 2 (iii) The research purposes of the project. (iv) The source and type of funding for the project. (v) The class and duration of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration. (3) Determination by the Administrator. (i) The Administrator shall determine if a project meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator shall take into account any information you submit demonstrating that the planned duration of CO 2 2 (ii) Any appeal of the Administrator's determination is subject to the provisions of part 78 of this chapter. (iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator's determination. You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan. § 98.441 Reporting threshold. (a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO 2 (b) Request for discontinuation of reporting. (1) Timing of request. (2) Content of request. (i) For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control program Director's authorization of site closure. (ii) For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO 2 (3) Notification. § 98.442 GHGs to report. You must report: (a) Mass of CO 2 (b) Mass of CO 2 (c) Mass of CO 2 (d) Mass of CO 2 (e) Mass of CO 2 2 (f) Mass of CO 2 2 (g) Mass of CO 2 (h) Cumulative mass of CO 2 [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73905, Nov. 29, 2011] § 98.443 Calculating CO 2 You must calculate the mass of CO 2 2 2 2 (a) You must calculate and report the annual mass of CO 2 (1) For a mass flow meter, you must calculate the total annual mass of CO 2 2 2 where: CO 2T,r 2 Q r,p S r,p C CO2,p,r 2 2 p = Quarter of the year. r = Receiving flow meter. (2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 2 2 2 where: CO 2T,r 2 Q r,p S r,p D = Density of CO 2 C CO2,p,r 2 2 p = Quarter of the year. r = Receiving flow meter. (3) If you receive CO 2 2 where: CO 2 2 CO 2T,r 2 r = Receiving flow meter. (b) You must calculate and report the annual mass of CO 2 (1) If you are measuring the mass of contents in a container under the provisions of § 98.444(a)(2)(i), you must calculate the CO 2 where: CO 2T,r 2 C CO2,p,r 2 2 Q r,p S r,p p = Quarter of the year. r = Containers. (2) If you are measuring the volume of contents in a container under the provisions of § 98.444(a)(2)(ii), you must calculate the CO 2 where: CO 2T,r 2 C CO2,p,r 2 2 Q r,p S r,p D = Density of the CO 2 p = Quarter of the year. r = Containers. (c) You must report the annual mass of CO 2 (1) If you use a mass flow meter to measure the flow of an injected CO 2 2 2 2 where: CO 2,u 2 Q p,u C CO2,p,u 2 2 p = Quarter of the year. u = Flow meter. (2) If you use a volumetric flow meter to measure the flow of an injected CO 2 2 2 2 2 where: CO 2,u 2 Q p,u D = Density of CO 2 C CO2,p,u 2 2 p = Quarter of the year. u = Flow meter. (3) To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO 2 where: CO 2I 2 CO 2,u 2 u = Flow meter. (d) You must calculate the annual mass of CO 2 2 2 (1) For each gas-liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO 2 2 Where: CO 2,w 2 Q p,w C CO2,p,w 2 2 p = Quarter of the year. w = Separator. (2) For each gas-liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO 2 2 2 Where: CO 2,w 2 Q p,w D = Density of CO 2 C CO2,p,w 2 2 p = Quarter of the year. w = Separator. (3) To aggregate production data, you must sum the mass of all of the CO 2 2 2 2 2 2 2 2 Where: CO 2P 2 CO 2,w 2 X = Entrained CO 2 2 2 w = Separator. (e) You must report the annual mass of CO 2 2 where: CO 2E 2 CO 2,x 2 x = Leakage pathway. (f) You must report the annual mass of CO 2 (1) If you are actively producing oil or natural gas or if you are producing any other fluids, you must calculate the annual mass of CO 2 where: CO 2 2 CO 2I 2 CO 2P 2 CO 2E 2 CO 2FI 2 2 CO 2FP 2 2 (2) If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO 2 where: CO 2 2 CO 2I 2 CO 2E 2 CO 2FI 2 2 [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011; 78 FR 71978, Nov. 29, 2013] § 98.444 Monitoring and QA/QC requirements. (a) CO 2 received. 2 (i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly. (ii) If you took ownership of the CO 2 (iii) If you inject CO 2 2 2 (2) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO 2 (i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells. (ii) You may determine the volume of the contents of containers summed quarterly. (iii) If you took ownership of the CO 2 (3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO 2 2 (i) You may sample the CO 2 2 (ii) If you took ownership of the CO 2 2 2 2 2 (iii) If you inject CO 2 2 2 (4) If the CO 2 2 2 2 2 (5) You must assume that the CO 2 2 2 (b) CO 2 injected. 2 2 (2) You must measure flow rate of CO 2 (3) You must sample the injected CO 2 2 2 (c) CO 2 produced. 2 (2) You must sample the produced gas stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that gas stream and measure the CO 2 (3) You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly. (d) CO 2 emissions from equipment leaks and vented emissions of CO 2 (e) Measurement devices. (2) You must calibrate all flow meters used to measure quantities reported in § 98.446 according to the calibration and accuracy requirements in § 98.3(i). (3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable. (f) General. 2 (2) You must convert all measured volumes of CO 2 (3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods only for parameters required by paragraphs (a) and (b) of § 98.443 rather than follow the monitoring requirements of paragraph (a) of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011. [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011] § 98.445 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures: (a) A quarterly flow rate of CO 2 (1) Another calculation methodology listed in § 98.444(a)(1) must be used if possible. (2) If another method listed in § 98.444(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) A quarterly mass or volume of contents in containers received that is missing must be estimated as follows: (1) Another calculation methodology listed in § 98.444(a)(2) must be used if possible. (2) If another method listed in § 98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period. (c) A quarterly CO 2 2 (1) Another calculation methodology listed in § 98.444(a)(3) must be used if possible. (2) If another method listed in § 98.444(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period. (d) A quarterly quantity of CO 2 2 (e) For any values associated with CO 2 2 (f) The quarterly quantity of CO 2 2 (g) You must estimate the mass of CO 2 (h) You must estimate other missing data as required by your approved MRV plan. [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011] § 98.446 Data reporting requirements. In addition to the information required by § 98.3(c), report the information listed in this section. (a) If you receive CO 2 (1) The total net mass of CO 2 (2) If a volumetric flow meter is used to receive CO 2 (i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter. (ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter. (iii) The CO 2 2 (3) If a mass flow meter is used to receive CO 2 (i) The mass flow through a receiving flow meter (in metric tons) in each quarter. (ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter. (iii) The CO 2 2 (4) If the CO 2 2 (5) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section. (6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section. (7) Whether the flow meter is mass or volumetric. (8) A numerical identifier for the flow meter. (b) If you receive CO 2 (1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter. (2) The concentration of CO 2 2 (3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter. (4) The net mass of CO 2 (5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section. (6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section. (c) If you use more than one receiving flow meter, report the total net mass of CO 2 (d) The source of the CO 2 (1) CO 2 (2) Electric generating unit. (3) Ethanol plant. (4) Pulp and paper mill. (5) Natural gas processing. (6) Gasification operations. (7) Other anthropogenic source. (8) Discontinued enhanced oil and gas recovery project. (9) Unknown. (e) Report the date that you began collecting data for calculating total amount sequestered according to § 98.448(a)(7) of this subpart. (f) Report the following. If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section. (1) For each injection flow meter (mass or volumetric), report: (i) The mass of CO 2 (ii) The CO 2 2 (iii) If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter. (iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter. (v) A numerical identifier for the flow meter. (vi) Whether the flow meter is mass or volumetric. (vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section. (viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section. (ix) The location of the flow meter. (2) The total CO 2 (3) For CO 2 2 (i) The mass of CO 2 2 (ii) The mass of CO 2 2 (4) For each separator flow meter (mass or volumetric), report: (i) CO 2 (ii) CO 2 2 (iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter. (iv) If a mass flow meter, mass flow rate (metric tons) in each quarter. (v) A numerical identifier for the flow meter. (vi) Whether the flow meter is mass or volumetric. (vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section. (viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section. (5) The entrained CO 2 2 2 (6) Annual CO 2 (7) For each leakage pathway through which CO 2 (i) A numerical identifier for the leakage pathway. (ii) The CO 2 (8) Annual CO 2 (9) Annual CO 2 (10) Cumulative mass of CO 2 (11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA. (12) An annual monitoring report that contains the following components: (i) A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted. (ii) A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under § 98.448(d). (iii) A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved. (iv) A description of any surface leakages of CO 2 2 (13) If a well is permitted under the Underground Injection Control program, for each injection well, report: (i) The well identification number used for the Underground Injection Control permit. (ii) The Underground Injection Control permit class. (14) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration. [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011; 78 FR 71979, Nov. 29, 2013] § 98.447 Records that must be retained. (a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a)(1) through (7) of this section, as applicable. You must retain all required records for at least 3 years. (1) Quarterly records of CO 2 (2) Quarterly records of produced CO 2 (3) Quarterly records of injected CO 2 (4) Annual records of information used to calculate the CO 2 (5) Annual records of information used to calculate the CO 2 2 (6) Annual records of information used to calculate the CO 2 2 (7) Any other records as specified for retention in your EPA-approved MRV plan. (b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data. [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73906, Nov. 29, 2011] § 98.448 Geologic sequestration monitoring, reporting, and verification (MRV) plan. (a) Contents of MRV plan. (1) Delineation of the maximum monitoring area and the active monitoring areas. The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than 1 year. (2) Identification of potential surface leakage pathways for CO 2 2 (3) A strategy for detecting and quantifying any surface leakage of CO 2 (4) A strategy for establishing the expected baselines for monitoring CO 2 (5) A summary of the considerations you intend to use to calculate site-specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating CO 2 2 2 (6) If a well is permitted under the Underground Injection Control program, for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report the well identification numbers in the permit application. If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration. If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved. (7) Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart. This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detection and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial AMA. (b) Timing. (1) You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO 2 (2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO 2 2 (3) If you are injecting a CO 2 (4) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA. (c) Final MRV plan. (d) MRV plan revisions. (1) A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material changes include but are not limited to: Large changes in the volume of CO 2 (2) A change in the permit class of your Underground Injection Control permit. (3) If you are notified by EPA of substantive errors in your MRV plan or monitoring report. (4) You choose to revise your MRV plan for any other reason in any reporting year. (e) Revised MRV plan. (f) Format. (g) Certificate of representation. [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73907, Nov. 29, 2011] § 98.449 Definitions. Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Active monitoring area (1) The area projected to contain the free phase CO 2 (2) The area projected to contain the free phase CO 2 CO 2 received 2 2 2 2 Equipment leak Expected baseline Maximum monitoring area 2 2 Offshore Research and development project 2 2 Separator Surface leakage 2 Underground Injection Control permit et seq. Underground Injection Control program et seq. Vented emissions 4 2 [75 FR 75078, Dec. 1, 2010, as amended at 76 FR 73907, Nov. 29, 2011; 89 FR 31944, Apr. 25, 2024] Subpart SS—Electrical Equipment Manufacture or Refurbishment Source: 89 FR 31944, Apr. 25, 2024, unless otherwise noted. § 98.450 Definition of the source category. The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gas-containing components of such equipment) containing fluorinated GHGs, including but not limited to sulfur-hexafluoride (SF 6 § 98.451 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO 2 Where: E = Annual production process emissions for threshold applicability purposes (metric tons CO 2 P j GHG i,w GWP i EF = Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs purchased). For all gases, use an emission factor of 0.1. i = Fluorinated GHG contained in the electrical transmission and distribution equipment. 0.000453592 = Conversion factor from lbs to metric tons. § 98.452 GHGs to report. (a) You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, at the facility level, except you are not required to report emissions of fluorinated GHGs that are components of insulating gases whose weighted average GWPs, as calculated in equation SS-2 to this section, are less than or equal to one. You are, however, required to report certain quantities of insulating gases whose weighted average GWPs are less than or equal to one as specified in § 98.456(f), (g), (k) and (q) through (s). Annual emissions from the facility must include fluorinated GHG emissions from equipment that is installed at an off-site electric power transmission or distribution location whenever emissions from installation activities ( e.g., Where: GWP j GHG i,w GWP i i = GHG contained in the electrical transmission and distribution equipment. (b) You must report CO 2 2 4 § 98.453 Calculating GHG emissions. (a) For each electrical equipment manufacturer or refurbisher, estimate the annual emissions of each fluorinated GHG that is a component of any reportable insulating gas using the mass-balance approach in equation SS-3 to this section: Where: User emissions i GHG i,w Decrease in Inventory of Reportable Insulating Gas j Inventory = (Pounds of reportable insulating gas j stored in containers at the beginning of the year)—(Pounds of reportable insulating gas j stored in containers at the end of the year). Acquisitions of Reportable Insulating Gas j = (Pounds of reportable insulating gas j purchased from chemical producers or suppliers in bulk) + (Pounds of reportable insulating gas j returned by equipment users) + (Pounds of reportable insulating gas j returned to site after off-site recycling). Disbursements of Reportable Insulating Gas j = (Pounds of reportable insulating gas j contained in new equipment delivered to customers) + (Pounds of reportable insulating gas j delivered to equipment users in containers) + (Pounds of reportable insulating gas j returned to suppliers) + (Pounds of reportable insulating gas j sent off site for recycling) + (Pounds of reportable insulating gas j sent off-site for destruction). (b) [Reserved] (c) Estimate the disbursements of reportable insulating gas j sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers using equation SS-4 to this section: Where: D GHG Q p n = The number of periods in the year. (d) Estimate the mass of each insulating gas j disbursed to customers in new equipment or cylinders over the period p by monitoring the mass flow of each insulating gas j into the new equipment or cylinders using a flowmeter, or by weighing containers before and after gas from containers is used to fill equipment or cylinders, or by using the nameplate capacity of the equipment. (e) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is estimated by weighing containers before and after gas from containers is used to fill equipment or cylinders, estimate this quantity using equation SS-5 to this section: Where: Q p M B M E E L e.g., (f) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined using a flowmeter, estimate this quantity using equation SS-6 to this section: Where: Q p M mr E L e.g., (g) Estimate the mass of insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders ( e.g., Where: E L e.g., FC i EF Ci n=The number of different valve-hose combinations C used during the period p. (h) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined by using the nameplate capacity, or by using the nameplate capacity of the equipment and calculating the partial shipping charge, use the methods in either paragraph (h)(1) or (2) of this section. (1) Determine the equipment's actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f). (2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge. (i) Estimate the annual emissions of reportable insulating gas j from the equipment that is installed at an off-site electric power transmission or distribution location before the title to the equipment is transferred by using equation SS-8 to this section: Where: EI = Total annual emissions of reportable insulating gas j from equipment installation at electric transmission or distribution facilities. GHG i,w M F M C N I § 98.454 Monitoring and QA/QC requirements. (a) [Reserved] (b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and precision of ±1 percent of full scale or better or scales with an accuracy and precision of ±1 percent of the filled weight (gas plus tare) of the containers of each reportable insulating gas that are typically weighed on the scale. For scales that are generally used to weigh cylinders containing 115 pounds of gas when full, this equates to ±1 percent of the sum of 115 pounds and approximately 120 pounds tare, or slightly more than ±2 pounds. Account for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier ( e.g., (c) All flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities under this subpart must be calibrated using calibration procedures specified by the flowmeter, scale, volumetric or density measure equipment manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer. (d) For purposes of equation SS-7 to § 98.453, the emission factor for the valve-hose combination (EFC) must be estimated using measurements and/or engineering assessments or calculations based on chemical engineering principles or physical or chemical laws or properties. Such assessments or calculations may be based on, as applicable, the internal volume of hose or line that is open to the atmosphere during coupling and decoupling activities, the internal pressure of the hose or line, the time the hose or line is open to the atmosphere during coupling and decoupling activities, the frequency with which the hose or line is purged and the flow rate during purges. You must develop a value for EFc (or use an industry-developed value) for each combination of hose and valve fitting, to use in equation SS-7 to § 98.453. The value for EFC must be determined for each combination of hose and valve fitting of a given diameter or size. The calculation must be recalculated annually to account for changes to the specifications of the valves or hoses that may occur throughout the year. (e) Electrical equipment manufacturers and refurbishers must account for emissions of each reportable insulating gas that occur as a result of unexpected events or accidental losses, such as a malfunctioning hose or leak in the flow line, during the filling of equipment or containers for disbursement by including these losses in the estimated mass of each reportable insulating gas emitted downstream of the container or flowmeter during the period p. (f) If the mass of each reportable insulating gas j disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped with a partial charge, equal to its partial shipping charge, equipment samples for conducting the nameplate capacity tests must be selected using the following stratified sampling strategy in this paragraph (f). For each make and model, group the measurement conditions to reflect predictable variability in the facility's filling practices and conditions ( e.g., (g) Ensure the following QA/QC methods are employed throughout the year: (1) Procedures are in place and followed to track and weigh all cylinders or other containers at the beginning and end of the year. (2) [Reserved] (h) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting: (1) Review inputs to equation SS-3 to § 98.453 to ensure inputs and outputs to the company's system are included. (2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in the inventory for each reportable insulating gas may be calculated as negative. (3) Ensure that for each reportable insulating gas, the beginning-of-year inventory matches the end-of-year inventory from the previous year. (4) Ensure that for each reportable insulating gas, in addition to the reportable insulating gas purchased from bulk gas distributors, the reportable insulating gas returned from equipment users with or inside equipment and the reportable insulating gas returned from off-site recycling are also accounted for among the total additions. § 98.455 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from similar manufacturing operations, and from similar equipment testing and decommissioning activities for which data are available. § 98.456 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each chemical at the facility level: (a) Pounds of each reportable insulating gas stored in containers at the beginning of the year. (b) Pounds of each reportable insulating gas stored in containers at the end of the year. (c) Pounds of each reportable insulating gas purchased in bulk. (d) Pounds of each reportable insulating gas returned by equipment users with or inside equipment. (e) Pounds of each reportable insulating gas returned to site from off site after recycling. (f) Pounds of each insulating gas inside new equipment delivered to customers. (g) Pounds of each insulating gas delivered to equipment users in containers. (h) Pounds of each reportable insulating gas returned to suppliers. (i) Pounds of each reportable insulating gas sent off site for destruction. (j) Pounds of each reportable insulating gas sent off site to be recycled. (k) The nameplate capacity of the equipment, in pounds, delivered to customers with each insulating gas inside, if different from the quantity in paragraph (f) of this section. (l) A description of the engineering methods and calculations used to determine emissions from hoses or other flow lines that connect the container to the equipment that is being filled. (m) The values for EF ci (n) The total number of fill operations for each hose and valve combination, or, FC i (o) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the mean value of nameplate capacity in pounds for each make, model, and group of conditions. (p) If the mass of each reportable insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the number of samples and the upper and lower bounds on the 95-percent confidence interval for each make, model, and group of conditions. (q) Pounds of each insulating gas used to fill equipment at off-site electric power transmission or distribution locations, or MF, of equation SS-8 to § 98.453. (r) Pounds of each insulating gas used to charge the equipment prior to leaving the electrical equipment manufacturer or refurbishment facility, or MC, of equation SS-8 to § 98.453. (s) The nameplate capacity of the equipment, in pounds, installed at off-site electric power transmission or distribution locations used to determine emissions from installation, or N I (t) For any missing data, you must report the reason the data were missing, the parameters for which the data were missing, the substitute parameters used to estimate emissions in their absence, and the quantity of emissions thereby estimated. (u) For each insulating gas reported in paragraphs (a) through (j) and (o) through (r) of this section, an ID number or other appropriate descriptor unique to that insulating gas. (v) For each ID number or descriptor reported in paragraph (u) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)( 1 § 98.457 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the following records: (a) All information reported and listed in § 98.456. (b) Accuracy certifications and calibration records for all scales and monitoring equipment, including the method or manufacturer's specification used for calibration. (c) Certifications of the quantity of gas, in pounds, charged into equipment at the electrical equipment manufacturer or refurbishment facility as well as the actual quantity of gas, in pounds, charged into equipment at installation. (d) Check-out and weigh-in sheets and procedures for cylinders. (e) Residual gas amounts, in pounds, in cylinders sent back to suppliers. (f) Invoices for gas purchases and sales. (g) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. § 98.458 Definitions. Except as specified in this section, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part. Insulating gas 6 Reportable insulating gas Subpart TT—Industrial Waste Landfills Source: 75 FR 39773, July 12, 2010, unless otherwise noted. § 98.460 Definition of the source category. (a) This source category applies to industrial waste landfills that accepted waste on or after January 1, 1980, and that are located at a facility whose total landfill design capacity is greater than or equal to 300,000 metric tons. (b) An industrial waste landfill (c) This source category does not include: (1) Construction and demolition waste landfills. (2) Industrial waste landfills that only receive one or more of the following inert waste materials: (i) Coal combustion or incinerator ash ( e.g., (ii) Cement kiln dust. (iii) Rocks and/or soil from excavation and construction and similar activities. (iv) Glass. (v) Non-chemically bound sand ( e.g., (vii) Clay, gypsum, or pottery cull. (viii) Bricks, mortar, or cement. (ix) Furnace slag. (x) Materials used as refractory ( e.g., (xi) Plastics ( e.g., (xii) Other waste material that has a volatile solids concentration of 0.5 weight percent (on a dry basis) or less. (xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i). (d) This source category consists of the following sources at industrial waste landfills: Landfills, gas collection systems at landfills, and destruction devices for landfill gases (including flares). [75 FR 39773, July 12, 2010, as amended at 76 FR 73907, Nov. 29, 2011, 77 FR 51495, Aug. 24, 2012; 78 FR 71979, Nov. 29, 2013] § 98.461 Reporting threshold. You must report GHG emissions under this subpart if your facility contains an industrial waste landfill meeting the criteria in § 98.460 and the facility meets the requirements of § 98.2(a)(2). For the purposes of § 98.2(a)(2), the emissions from the industrial waste landfill are to be determined using the methane generation corrected for oxidation as determined using Equation TT-6 of this subpart times the global warming potential for methane in Table A-1 of subpart A of this part. § 98.462 GHGs to report. (a) You must report CH 4 4 (b) You must report CH 4 (c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO 2 4 2 § 98.463 Calculating GHG emissions. (a) For each industrial waste landfill subject to the reporting requirements of this subpart, calculate annual modeled CH 4 4 4 (1) Calculate annual modeled CH 4 Where: G CH4 4 X = Year in which waste was disposed. S = Start year of calculation. Use the year 1960 or the opening year of the landfill, whichever is more recent. T = Reporting year for which emissions are calculated. W X DOC X DOC F MCF = Methane correction factor (fraction). Use the default value of 1 unless there is active aeration of waste within the landfill during the reporting year. If there is active aeration of waste within the landfill during the reporting year, use either the default value of 1 or select an alternative value no less than 0.5 based on site-specific aeration parameters. F = Fraction by volume of CH 4 4 k = Decay rate constant from Table TT-1 to this subpart (yr−1). Select the most applicable k value for the majority of the past 10 years (or operating life, whichever is shorter). (2) Waste stream quantities. i.e., (i) Determine the quantity of waste (in metric tons as received, i.e., (A) Direct mass measurements. (B) Direct volume measurements multiplied by waste stream density determined from periodic density measurement data or process knowledge. (C) Mass balance procedures, determining the mass of waste as the difference between the mass of the process inputs and the mass of the process outputs. (D) The number of loads ( e.g., (ii) Determine the historical disposal quantities for landfills using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and (B) of this section when historical production or processing data are available. If production or processing data are available for a given year, you must use Equation TT-3 of this section for that year. Determine historical disposal quantities using the method specified in paragraph (a)(2)(ii)(C) of this section when historical production or processing data are not available, and for waste streams received from an off-site facility when historical disposal quantities cannot be determined using the methods specified in paragraph (a)(2)(i) of this section. (A) Determining Waste Disposal Factor: Where: WDF = Average waste disposal factor as determined for the first annual report required for this industrial waste landfill (metric tons per production unit). X = Year in which waste was disposed. Include only those years for which disposal and production data are both available; the years do not need to be sequential. Y 1 Y 2 N = Number of years for which disposal and production/throughput data are both available. W x P x x x (B) Calculate waste: Where: X = Historic year in which waste was disposed. W x WDF = Average waste disposal factor from Equation TT-2 of this section (metric tons per production unit). P x x (C) For any year in which historic production or processing data are not available such that historic waste quantities cannot be estimated using Equation TT-3 of this section, calculate an average annual bulk waste disposal quantity using either Equation TT-4a of this section when data are available consecutively for the most recent disposal years or Equation TT-4b of this section when data are available for sporadic (non-consecutive) years. Where: W X LFC = Capacity of the landfill used (or the total quantity of waste-in-place) at the end of the “YrData” from design drawings or engineering estimates (metric tons). For closed landfills for which waste quantity data are not available, use the landfill's design capacity. YrData = The year prior to the year when waste disposal data are first available for all subsequent years from company records or from Equation TT-3 of this section. For landfills for which waste quantity data are not available, the year in which the landfill last received waste. YrOpen = Year 1960 or the year in which the landfill first received waste from company records, whichever is more recent. If no data are available for estimating YrOpen for a closed landfill, use 1960 as the default “YrOpen” for the landfill. Where: W X WIP = Quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons). For closed landfills for which waste in-place quantities are not available, use the landfill's design capacity. W meas,n YrLast = The last year, prior to the reporting year, that the landfill received waste. YrOpen = Year 1960 or the year in which the landfill first received waste from company records, whichever is more recent. If no data are available for estimating YrOpen for a closed landfill, use 1960 as the default “YrOpen” for the landfill. NYrData = The number of years for which annual waste disposal quantities are available from company records or from Equation TT-3 of this section from YrOpen to YrLast inclusive. (3) Degradable organic content (DOC). x x x e.g., (i) For the first year in which GHG emissions from this industrial waste landfill must be reported, determine the DOC x x x (ii) For subsequent years (after the first year in which GHG emissions from this industrial waste landfill must be reported), either use the DOC x x (iii) If DOC x x x x (iv) For historical years for which DOC x x x x (A) For years in which waste stream-specific disposal quantities are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this section), calculate the average DOC value for a given waste stream as the arithmetic average of all DOC measurements of that waste stream that follow the methods provided in § 98.464(b), including any measurement values for years prior to the first reporting year and the four measurement values required in the first reporting year. Use the resulting waste-specific average DOC value for all applicable years ( i.e., (B) For years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section, calculate the weighted average bulk DOC value according to the following: Calculate the average DOC value for each waste stream as the arithmetic average of all DOC measurements of that waste stream that follows the methods provided in § 98.464(b) (generally, this will include only the DOC values determined in the first year in which GHG emissions from this industrial waste landfill must be reported); calculate the average annual disposal quantity for each waste stream as the arithmetic average of the annual disposal quantities for each year in which waste stream-specific disposal quantities have been determined; and calculate the bulk waste DOC value using Equation TT-5 of this section. Use the bulk waste DOC value as DOC x Where: DOC bulk N = Number of different waste streams placed in the landfill. n = Index for waste stream. DOC ave,n W ave,n (b) For each landfill, calculate CH 4 4 4 (1) For each landfill, calculate CH 4 4 CH 4 Where: MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH 4 G CH 4 4 OX = Oxidation fraction from Table HH-4 of subpart HH of this part. (2) For landfills that do not have landfill gas collection systems operating during the reporting year, the CH 4 4 (3) For landfills with landfill gas collection systems in operation during any portion of the reporting year, perform all of the calculations specified in paragraphs (b)(3)(i) through (iv) of this section. (i) Calculate the quantity of CH 4 (ii) Calculate CH 4 CH 4 (iii) Calculate CH 4 4 (iv) Calculate CH 4 4 [75 FR 39773, July 12, 2010, as amended at 76 FR 73907, Nov. 29, 2011; 78 FR 71979, Nov. 29, 2013] § 98.464 Monitoring and QA/QC requirements. (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) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC X (1) Develop and follow a sampling plan to collect a representative sample (in terms of composition and moisture content) of each waste stream placed in the landfill for which testing is elected. (2) Determine the percent total solids and the percent volatile solids of each sample following Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see (3) For the purposes of § 98.460(c)(2)(xii), the volatile solids concentration (weight percent on a dry basis) is the percent volatile solids determined using Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7). (4) Determine DOC value of a waste stream by either using at least a 60-day anaerobic biodegradation test as specified in paragraph (b)(4)(i) of this section or by estimating the DOC value based on the total and volatile solids measurements as specified in paragraph (b)(4)(ii) of this section. (i) Perform an anaerobic biodegradation test and determine the DOC value of a waste stream following the procedures and requirements in paragraphs (b)(4)(i)(A) through (E) of this section. (A) You may use the procedures published by a consensus-based standards organization to conduct a minimum of a 60-day anaerobic biodegradation test. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org http://www.ansi.org http://www.asme.org http://www.api.org (B) Use a minimum of four samples: Two waste stream samples, a control sample using a known substrate (such as ethanol), and a digester sludge blank sample. Each waste stream sample must be appropriately ground to ensure the waste material is fully exposed to the anaerobic digester sludge. (C) Determine the net mass of carbon degraded in the control sample as the difference in the results of the control sample and the digester sludge blank sample. Determine the net mass of carbon degraded in each waste stream sample as the difference in the results of each waste stream sample and the digester sludge blank sample. (D) Determine the fraction of carbon degraded in the control sample as the net mass of carbon degraded in the control sample divided by the mass of carbon added via the substrate material in the control sample. If less than 50 percent of the theoretical mass of carbon in the control sample is degraded, the test run is invalid. (E) Determine the DOC of each waste sample using Equation TT-7 of this section. If the DOC values for the two waste stream samples differ by more than 20 percent, the test run is invalid. The DOC of the waste stream is determined as the average DOC value of the two waste stream samples determined during a valid test. Where: DOC X MCD sample,x M sample,x (ii) Calculate the waste stream-specific DOC X Where: DOC X F DOC % Volatile Solids X % Total Solids X (c) For each waste stream that was historically managed in the landfill for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC X X (1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration or DOC X (2) If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration or DOC X X (d) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH 4 (e) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas according to the requirements specified at § 98.344(c). (f) For landfills with gas collection systems, all temperature, pressure, and if applicable, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer. (g) For landfills electing to measure the fraction by volume of CH 4 (1) Use a gas composition monitor capable of measuring the concentration of CH 4 2 2 (2) Use Equation TT-9 of this section to correct the measured CH 4 4 Where: F = Fraction by volume of CH 4 C CH4 4 20.9 c 2 20.9 = O 2 %O 2 2 (h) The facility shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if the industrial waste landfill has a gas collection system, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided. [75 FR 39773, July 12, 2010, as amended at 76 FR 73908, Nov. 29, 2011; 77 FR 51495, Aug. 24, 2012; 78 FR 71979, Nov. 29, 2013] § 98.465 Procedures for estimating missing data. (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., (b) For industrial waste landfills with gas collection systems, follow the procedures for estimating missing data specified in § 98.345(a) and (b). § 98.466 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill. (a) Report the following general landfill information: (1) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste). (2) The year in which the landfill first started accepting waste for disposal. (3) The last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure). (4) The capacity (in metric tons) of the landfill. (5) An indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years ( e.g., (b) Report the following waste characterization and modeling information: (1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts”) for which Equation TT-1 of this subpart is used to calculate modeled CH 4 (2) A description of each waste stream (including the types of materials in each waste stream) for which Equation TT-1 of this subpart is used to calculate modeled CH 4 (3) The fraction of CH 4 (4) The methane correction factor (MCF) value used in the calculations. If an MCF value other than the default of 1 is used, provide a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value. (5) For each waste stream, the decay rate (k) value used in the calculations. (c) Report the following historical waste information: (1) [Reserved] (2) For each waste stream identified in paragraph (b) of this section, the method(s) for estimating historical waste disposal quantities and the range of years for which each method applies. (3) For each waste stream identified in paragraph (b) of this section for which Equation TT-2 of this subpart is used, provide: (i) [Reserved] (ii) The year of the data used in Equation TT-2 of § 98.463 for the waste disposal quantity and production quantity, for each year used in Equation TT-2 to calculate the average waste disposal factor (WDF). (iii) [Reserved] (4) If Equation TT-4a of this subpart is used, provide: (i) The value of landfill capacity (LFC). (ii) YrData. (iii) YrOpen. (5) If Equation TT-4b of this subpart is used, provide: (i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are not available, the landfill's design capacity). (ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities are available from company record or from Equation TT-3 of this part. (iii) YrLast. (iv) YrOpen. (v) NYrData. (d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter up to the current reporting year, report the following information: (1) The calendar year for which the following data elements apply. (2) The quantity of waste (W X (3) For each waste stream, the degradable organic carbon (DOC X X (e) Report the following information describing the landfill cover material: (1) The type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures). (2) For each type of cover material used, the surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type. (f) The modeled annual methane generation (G CH4 4 (g) For landfills without gas collection systems, provide: (1) The annual methane emissions ( i.e. 4 (2) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at this landfill. (h) For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, provide: (1) The annual methane generation, adjusted for oxidation, calculated using Equation TT-6 of this subpart, reported in metric tons CH 4 (2) The oxidation factor used in Equation TT-6 of this subpart. (3) All information required under 40 CFR 98.346(i)(1) through (7) and 40 CFR 98.346(i)(9) through (12). [75 FR 39773, July 12, 2010, as amended at 76 FR 73909, Nov. 29, 2011; 78 FR 71980, Nov. 29, 2013; 79 FR 63799, Oct. 24, 2014] § 98.467 Records that must be retained. (a) The calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration, and all measurement data used for the purposes of § 98.460(c)(2)(xii) or (xiii) or used to determine waste stream-specific DOC X (b) Verification software records. (1) Quantity of each product produced or feedstock entering the process or facility per waste stream per year, from measurement data and/or other company records. You must use the same basis for all years in the calculation (i.e., based on production or based on quantity of feedstock) (metric tons) (Equation TT-2 of § 98.463). (2) [Reserved] [79 FR 63799, Oct. 24, 2014] § 98.468 Definitions. Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part. Construction and demolition (C&D) waste landfill Design capacity design capacity Industrial sludge Industrial sludge Industrial sludge Solid waste et seq. Waste stream [75 FR 39773, July 12, 2010, as amended at 76 FR 73910, Nov. 29, 2011; 78 FR 71980, Nov. 29, 2013] Table TT-1 to Subpart TT of Part 98—Default DOC and Decay Rate Values for Industrial Waste Landfills Industry/Waste Type DOC k a −1 k a −1 k a −1 Food Processing (other than industrial sludge) 0.22 0.06 0.12 0.18 Pulp and Paper Industry: Pulp and paper wastes segregated into separate streams: Boiler Ash 0.06 0.02 0.03 0.04 Wastewater Sludge 0.12 0.02 0.04 0.06 Kraft Recovery Wastes b 0.025 0.02 0.03 0.04 Other Pulp and Paper Wastes (not otherwise listed) 0.20 0.02 0.03 0.04 Pulp and paper wastes not segregated into separate streams: Pulp and paper manufacturing wastes, general (other than industrial sludge) 0.15 0.02 0.03 0.04 Wood and Wood Product (other than industrial sludge) 0.43 0.02 0.03 0.04 Construction and Demolition 0.08 0.02 0.03 0.04 Industrial Sludge c 0.09 0.02 0.04 0.06 Inert Waste [ i.e. 0 0 0 0 Other Industrial Solid Waste (not otherwise listed) 0.20 0.02 0.04 0.06 a Dry climate = precipitation plus recirculated leachate less than 20 inches/year; Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive); Wet climate = precipitation plus recirculated leachate greater than 40 inches/year. Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather than calculating the recirculated leachate rate. b c [75 FR 39773, July 12, 2010, as amended at 76 FR 73910, Nov. 29, 2011; 78 FR 71981, Nov. 29, 2013; 81 FR 89274, Dec. 9, 2016] Subpart UU—Injection of Carbon Dioxide Source: 75 FR 75086, Dec. 1, 2010, unless otherwise noted. § 98.470 Definition of the source category. (a) The injection of carbon dioxide (CO 2 2 (b) If you report under subpart RR of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells. (c) If you report under subpart VV of this part for a well or group of wells, you shall not report under this subpart for that well or group of wells. If you previously met the source category definition for subpart UU of this part for a project where CO 2 2 (d) A facility that is subject to this part only because it is subject to subpart UU of this part is not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2). [75 FR 75086, Dec. 1, 2010, as amended at 89 FR 31948, Apr. 25, 2024] § 98.471 Reporting threshold. (a) You must report under this subpart if your facility injects any amount of CO 2 (b) For purposes of this subpart, any reference to CO 2 2 § 98.472 GHGs to report. You must report the mass of CO 2 § 98.473 Calculating CO 2 (a) You must calculate and report the annual mass of CO 2 (1) For a mass flow meter, you must calculate the total annual mass of CO 2 2 2 where: CO 2T,r 2 Q r,p S r,p C CO2,p,r 2 2 p = Quarter of the year. r = Receiving flow meter. (2) For a volumetric flow meter, you must calculate the total annual mass of CO 2 2 2 2 where: CO 2T,r 2 Q r,p S r,p D = Density of CO 2 C CO2,p,r 2 2 p = Quarter of the year. r = Receiving flow meter. (3) If you receive CO 2 2 where: CO 2 2 CO 2T,r 2 r = Receiving flow meter. (b) You must calculate and report the annual mass of CO 2 (1) If you are measuring the mass of contents in a container under the provisions of § 98.474(a)(2)(i), you must calculate the CO 2 where: CO 2T,r 2 C CO2,p,r 2 2 Q r,p S r,p p = Quarter of the year. r = Containers. (2) If you are measuring the volume of contents in a container under the provisions of § 98.474(a)(2)(ii), you must calculate the CO 2 where: CO 2T,r 2 C CO2,p,r 2 2 S r,p Q r,p D = Density of the CO 2 p = Quarter of the year. r = Containers. [75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71981, Nov. 29, 2013] § 98.474 Monitoring and QA/QC requirements. (a) CO 2 received. 2 (i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly. (ii) If you took ownership of the CO 2 (iii) If you inject CO 2 2 2 (2) You must determine the quarterly mass or volume of contents in all containers if you receive CO 2 (i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells. (ii) You may determine the volume of the contents of containers summed quarterly. (iii) If you took ownership of the CO 2 (3) You must determine a quarterly concentration of the CO 2 2 (i) You may sample the CO 2 2 (ii) If you took ownership of the CO 2 2 2 2 2 (iii) If you inject CO 2 2 2 2 2 (4) You must assume that the CO 2 2 2 (b) Measurement devices. (2) You must calibrate all flow meters used to measure quantities reported in § 98.476 according to the calibration and accuracy requirements in § 98.3(i). (3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB). (4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable. (c) General. 2 (2) You must convert all measured volumes of CO 2 (3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011. [75 FR 75086, Dec. 1, 2010, as amended at 81 FR 89274, Dec. 9, 2016] § 98.475 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG quantities calculations is required. (a) Whenever the monitoring procedures for all facilities that used flow meters covered under this subpart cannot be followed to measure flow, the following missing data procedures must be followed: (1) Another calculation methodology listed in § 98.474(a)(1) must be used if possible. (2) If another method listed in § 98.474(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period. (b) Whenever the monitoring procedures of this subpart cannot be followed to measure quarterly quantity of CO 2 (1) Another calculation methodology listed in § 98.474(a)(2) must be used if possible. (2) If another method listed in § 98.474(a)(2) cannot be used, a quarterly mass or volume that is missing must be estimated using a representative mass or volume from the nearest previous time period. (c) Whenever the monitoring procedures cannot be followed to measure CO 2 (1) Another calculation methodology listed in § 98.474(a)(3) must be used if possible. (2) If another method listed in § 98.474(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period. § 98.476 Data reporting requirements. If you are subject to this part and report under this subpart, you are not required to report the information in § 98.3(c)(4) for this subpart. In addition to the information required by § 98.3(c)(1) through § 98.3(c)(3) and by § 98.3(c)(5) through § 98.3(c)(9), you must report the information listed in this section. (a) If you receive CO 2 (1) The total net mass of CO 2 (2) If a volumetric flow meter is used to receive CO 2 (i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter. (ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter. (iii) The CO 2 2 (3) If a mass flow meter is used to receive CO 2 (i) The mass flow through a receiving flow meter (in metric tons) in each quarter. (ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter. (iii) The CO 2 2 (4) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section. (5) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section. (6) Whether the flow meter is mass or volumetric. (b) If you receive CO 2 (1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers in each quarter. (2) The concentration of CO 2 2 (3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter. (4) The net total mass of CO 2 (5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section. (6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section. (c) If you use more than one receiving flow meter, report the net total mass of CO 2 (d) The source of the CO 2 (1) CO 2 (2) Electric generating unit. (3) Ethanol plant. (4) Pulp and paper mill. (5) Natural gas processing. (6) Gasification operations. (7) Other anthropogenic source. (8) Discontinued enhanced oil and gas recovery project. (9) Unknown. (e) Report the following: (1) Whether the facility received a Research and Development project exemption from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA. (2) Whether the facility includes a well or group of wells where a CO 2 (3) Whether the facility includes a well or group of wells where a CO 2 (4) Whether the facility includes a well or group of wells where a CO 2 (5) Whether the facility includes a well or group of wells where a CO 2 2 [75 FR 75078, Dec. 1, 2010, as amended at 78 FR 71981, Nov. 29, 2013] § 98.477 Records that must be retained. (a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain quarterly records of CO 2 (b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data. § 98.478 Definitions. Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. CO 2 received 2 2 2 2 Subpart VV—Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916 Source: 89 FR 31948, Apr. 25, 2024, unless otherwise noted. § 98.480 Definition of the source category. (a) This source category pertains to carbon dioxide (CO 2 2 (1) You are using the standard designated as CSA/ANSI ISO 27916:19, (incorporated by reference, see § 98.7) as a method of quantifying geologic sequestration of CO 2 (2) ou are not reporting under subpart RR of this part. (b) This source category does not include wells permitted as Class VI under the Underground Injection Control program. (c) If you are subject to only this subpart, you are not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (2). § 98.481 Reporting threshold. (a) You must report under this subpart if your CO 2 2 2 (b) The requirements of § 98.2(i) do not apply to this subpart. Once a CO 2 (1) Discontinuation of reporting under this subpart must follow the requirements set forth under Clause 10 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (2) CO 2 (i) Cessation of CO 2 (ii) Cessation of hydrocarbon production from the project reservoir; and (iii) Wells are plugged and abandoned unless otherwise required by the appropriate regulatory authority. (3) You must notify the Administrator of your intent to cease reporting and provide a copy of the CO 2 (c) If you previously met the source category definition for subpart UU of this part for your CO 2 2 2 § 98.482 GHGs to report. You must report the following from Clause 8 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7): (a) The mass of CO 2 2 (b) The mass of CO 2 2 (c) The mass of native CO 2 (d) The mass of CO 2 (e) The mass of CO 2 (f) The mass of CO 2 2 § 98.483 Calculating CO 2 You must calculate CO 2 (a) You must calculate the mass of CO 2 2 m stored 2 2 2 Equation 1 to paragraph (a) m stored m input m loss operations m loss EOR complex Where: m stored 2 m input 2 m received m native 2 2 m native m input m loss operations 2 m loss EOR complex 2 (b) The manner by which associated storage is quantified must assure completeness and preclude double counting. The annual mass of CO 2 2 (c) You must quantify the total mass of CO 2 m input (1) You must include the total mass of CO 2 2 m received (2) The CO 2 2 2 (i) The native CO 2 m native (ii) CO 2 2 2 (3) The sum of the quantities of allocated CO 2 2 (d) You must calculate the total mass of CO 2 m loss operations Equation 2 to paragraph (d) Where: m loss leakage facilities 2 2 m loss vent/flare 2 m loss entrained 2 2 m loss transfer 2 2 2 2 § 98.484 Monitoring and QA/QC requirements. You must use the applicable monitoring and quality assurance requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). § 98.485 Procedures for estimating missing data. Whenever the value of a parameter is unavailable or the quality assurance procedures set forth in § 98.484 cannot be followed, you must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). § 98.486 Data reporting requirements. In addition to the information required by § 98.3(c), the annual report shall contain the following information, as applicable: (a) The annual quantity of associated storage in metric tons of CO 2 m stored (b) The density of CO 2 2 (c) The annual quantity of CO 2 m input (1) The annual total mass of CO 2 2 2 2 m received (2) The annual mass of native CO 2 2 m native (d) The annual mass of CO 2 (e) The annual total mass of CO 2 m loss operations (1) Loss of CO 2 2 m loss leakage facilities (2) Loss of CO 2 m loss vent/flare (3) Loss of CO 2 m loss entrained (4) Loss of CO 2 2 2 m loss transfer (f) The total mass of CO 2 m loss EOR complex (g) Annual documentation that contains the following components as described in Clause 4.4 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7): (1) The formulas used to quantify the annual mass of associated storage, including the mass of CO 2 2 (2) The methods used to estimate missing data and the amounts estimated as described in Clause 9.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (3) The approach and method for quantification utilized by the operator, including accuracy, precision, and uncertainties (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (4) A statement describing the nature of validation or verification including the date of review, process, findings, and responsible person or entity. (5) Source of each CO 2 (6) A description of the procedures used to detect and characterize the total CO 2 (7) If only the mass of anthropogenic CO 2 2 (8) Any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided, including the mass balance calculations as well as information regarding monitoring and containment assurance, is accurate and complete. (h) Any changes made within the reporting year to containment assurance and monitoring approaches and procedures in the EOR operations management plan. § 98.487 Records that must be retained. You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must comply with the record retention requirements in Clause 9.1 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). § 98.488 EOR Operations Management Plan. (a) You must prepare and update, as necessary, a general EOR operations management plan that provides a description of the EOR complex and engineered system (see Clause 4.3(a) of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)), establishes that the EOR complex is adequate to provide safe, long-term containment of CO 2 (1) Geologic characterization of the EOR complex. (2) A description of the facilities within the CO 2 (3) A description of all wells and other engineered features in the CO 2 (4) The operations history of the project reservoir. (5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). (b) You must prepare initial documentation at the beginning of the quantification period, and include the following as described in the EOR operations management plan: (1) A description of the EOR complex and engineered systems (see Clause 5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (2) The initial containment assurance (see Clause 6.1.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (3) The monitoring program (see Clause 6.2 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (4) The quantification method to be used (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7)). (5) The total mass of previously injected CO 2 2 (c) The EOR operation management plan in paragraph (a) of this section and initial documentation in paragraph (b) of this section must be submitted to the Administrator with the annual report covering the first reporting year that the facility reports under this subpart. In addition, any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided is accurate and complete, must also be provided to the Administrator. (d) If the EOR operations management plan is updated, the updated EOR management plan must be submitted to the Administrator with the annual report covering the first reporting year for which the updated EOR operation management plan is applicable. § 98.489 Definitions. Except as provided in paragraphs (a) and (b) of this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additional terms and definitions are provided in Clause 3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see § 98.7). Subpart WW—Coke Calciners Source: 89 FR 31948, Apr. 25, 2024, unless otherwise noted. § 98.490 Definition of the source category. (a) A coke calciner is a process unit that heats petroleum coke to high temperatures for the purpose of removing impurities or volatile substances in the petroleum coke feedstock. (b) This source category consists of rotary kilns, rotary hearth furnaces, or similar process units used to calcine petroleum coke and also includes afterburners or other emission control systems used to treat the coke calcining unit's process exhaust gas. § 98.491 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a coke calciner and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.492 GHGs to report. You must report: (a) CO 2 4 2 (b) CO 2 4 2 § 98.493 Calculating GHG emissions. (a) Calculate GHG emissions required to be reported in § 98.492(a) using the applicable methods in paragraph (b) of this section. (b) For each coke calcining unit, calculate GHG emissions according to the applicable provisions in paragraphs (b)(1) through (4) of this section. (1) If you operate and maintain a CEMS that measures CO 2 2 2 2 2 (2) Calculate the CO 2 Equation 1 to paragraph (b)(2) Where: CO 2 2 2 m = Month index. M in,m CC GC.m M out,m M dust,m CC MPC,m 44 = Molecular weight of CO 2 12 = Atomic weight of C (kg/kg-mole). (3) Calculate CH4 emissions using equation 2 to this paragraph (b)(3). Equation 2 to paragraph (b)(3) Where: CH 4 4 CO 2 2 2 EmF 1 2 2 EmF 2 4 4 (4) Calculate N 2 Equation 3 to paragraph (b)(4) Where: N 2 2 CO 2 2 2 EmF 1 2 2 EmF 3 2 2 § 98.494 Monitoring and QA/QC requirements. (a) Flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO 2 (b) Determine the mass of petroleum coke monthly as required by equation 1 to § 98.493(b)(2) using mass measurement equipment meeting the requirements for commercial weighing equipment as described in NIST HB 44-2023 (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by NIST HB 44-2023 (incorporated by reference, see § 98.7) or the procedures specified by the manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer. (c) Determine the carbon content of petroleum coke as required by equation 1 § 98.493(b)(2) using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer. (1) ASTM D3176-15 (incorporated by reference, see § 98.7). (2) ASTM D5291-16 (incorporated by reference, see § 98.7). (3) ASTM D5373-21 (incorporated by reference, see § 98.7). (d) The owner or operator must document the procedures used to ensure the accuracy of the monitoring systems used including but not limited to calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded. § 98.495 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required ( e.g., e.g., (a) For missing auxiliary fuel use data, use the missing data procedures in subpart C of this part. (b) For each missing value of mass or carbon content of coke, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. (c) For missing CEMS data, you must use the missing data procedures in § 98.35. § 98.496 Data reporting requirements. In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (i) of this section for each coke calcining unit. (a) The unit ID number (if applicable). (b) Maximum rated throughput of the unit, in metric tons coke calcined/stream day. (c) The calculated CO 2 4 2 (d) A description of the method used to calculate the CO 2 e.g., (e) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year). (f) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year). (g) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records (metric tons/year) and an indication of whether coke dust is recycled to the unit ( e.g., (h) Annual average mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke). (i) Annual average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke). § 98.497 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section. (a) The records of all parameters monitored under § 98.494. (b) The applicable verification software records as identified in this paragraph (b). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (b)(1) through (5) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (5) of this section. (1) Monthly mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (2) Monthly mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (3) Monthly mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records (metric tons/year) (equation 1 to § 98.493(b)(2)). (4) Average monthly mass fraction carbon content of green coke fed to the coke calcining unit from facility measurement data (metric tons C per metric ton green coke) (equation 1 to § 98.493(b)(2)). (5) Average monthly mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke) (equation 1 to § 98.493(b)(2)). § 98.498 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart XX—Calcium Carbide Production Source: 89 FR 31948, Apr. 25, 2024, unless otherwise noted. § 98.500 Definition of the source category. The calcium carbide production source category consists of any facility that produces calcium carbide. § 98.501 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a calcium carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.502 GHGs to report. You must report: (a) Process CO 2 (b) CO 2 4 2 § 98.503 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) Calculate and report under this subpart the combined process and combustion CO 2 (b) Calculate and report under this subpart the annual process CO 2 (1) For each calcium carbide process unit, determine the annual mass of carbon in each carbon-containing input and output material for the calcium carbide process unit and estimate annual process CO 2 Equation 1 to paragraph (b)(1) Where: E CO2 2 44/12 = Ratio of molecular weights, CO 2 2000/2205 = Conversion factor to convert tons to metric tons. M reducing agent i C reducing agent i M electrode m C electrode m M product outgoing k C product outgoing k M non-product outgoing l C non-product outgoing (2) Determine the combined annual process CO 2 Equation 2 to paragraph (b)(2) CO 2 k CO2 k Where: CO 2 2 E CO2 k 2 k = Total number of calcium carbide process units at facility. (c) If all GHG emissions from a calcium carbide process unit are vented through the same stack as any combustion unit or process equipment that reports CO 2 § 98.504 Monitoring and QA/QC requirements. If you determine annual process CO 2 (a) Determine the annual mass for each material used for the calculations of annual process CO 2 (b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output. (1) Information provided by your material supplier. (2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) and (ii) of this section, as applicable. (i) ASTM D5373-08 (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes. (ii) ASTM C25-06 (incorporated by reference, see § 98.7) for analysis of materials such as limestone or dolomite. § 98.505 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in § 98.503 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates. (a) If you determine CO 2 (b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must be based on the best available estimate of the mass of the inputs and outputs from all available process data or data used for accounting purposes, such as purchase records. § 98.506 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (h) of this section, as applicable: (a) Annual facility calcium carbide production capacity (tons). (b) The annual facility production of calcium carbide (tons). (c) Total number of calcium carbide process units at facility used for production of calcium carbide. (d) Annual facility consumption of petroleum coke (tons). (e) Each end use of any calcium carbide produced and sent off site. (f) If the facility produces acetylene on site, provide the information in paragraphs (f)(1) through (3) of this section. (1) The annual production of acetylene at the facility (tons). (2) The annual quantity of calcium carbide used for the production of acetylene at the facility (tons). (3) Each end use of any acetylene produced on-site. (g) If a CEMS is used to measure CO 2 (1) Annual CO 2 (2) Identification number of each process unit. (h) If a CEMS is not used to measure CO 2 2 (1) Annual process CO 2 (2) List the method used for the determination of carbon content for each input and output material included in the calculation of annual process CO 2 i.e., (3) If you use the missing data procedures in § 98.505(b), you must report for each calcium carbide production process unit how monthly mass of carbon-containing inputs and outputs with missing data were determined and the number of months the missing data procedures were used. § 98.507 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each calcium carbide process unit, as applicable. (a) If a CEMS is used to measure CO 2 (1) Monthly calcium carbide process unit production quantity (tons). (2) Number of calcium carbide processing unit operating hours each month. (3) Number of calcium carbide processing unit operating hours in a calendar year. (b) If the carbon mass balance procedure is used to determine CO 2 (1) Monthly calcium carbide process unit production quantity (tons). (2) Number of calcium carbide process unit operating hours each month. (3) Number of calcium carbide process unit operating hours in a calendar year. (4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO 2 (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 (c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each calcium carbide process unit, including documentation of specific input or output materials excluded from equation 1 to § 98.503(b)(1) that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in a calcium carbide process unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (8) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (8) of this section. (1) Carbon content in reducing agent (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (2) Annual mass of reducing agent fed, charged, or otherwise introduced into the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (3) Carbon content of carbon electrode (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (4) Annual mass of carbon electrode consumed in the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (5) Carbon content in product (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (6) Annual mass of product produced/tapped in the calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). (7) Carbon content in non-product outgoing material (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.503(b)(1)). (8) Annual mass of non-product outgoing material removed from calcium carbide process unit (tons) (equation 1 to § 98.503(b)(1)). § 98.508 Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Subpart YY—Caprolactam, Glyoxal, and Glyoxylic Acid Production Source: 89 FR 31948, Apr. 25, 2024, unless otherwise noted. § 98.510 Definition of the source category. This source category includes any facility that produces caprolactam, glyoxal, or glyoxylic acid. This source category excludes the production of glyoxal through the LaPorte process ( i.e., § 98.511 Reporting threshold. You must report GHG emissions under this subpart if your facility meets the requirements of either § 98.2(a)(1) or (2) and the definition of source category in § 98.510. § 98.512 GHGs to report. (a) You must report N 2 (b) You must report under subpart C of this part the emissions of CO 2 4 2 § 98.513 Calculating GHG emissions. (a) You must determine annual N 2 2 2 2 (b) You must determine the total annual amount of product i t (c) If process line t 2 j 2 (1) Use the control device manufacturer's specified destruction efficiency. (2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency. (d) If process line t 2 j 2 (1) If the abatement technology j (2) If the abatement technology j i t Equation 1 to paragraph (d)(2) Where: AF j 2 j t T i,j i t 2 j T i i t (e) You must calculate N 2 i t 2 j Equation 2 to paragraph (e) Where: E N2Ot 2 t EF i 2 i 2 P i i DE j 2 j 2 AF j 2 j 0.001 = Conversion factor from kg to metric tons. (f) You must determine the annual emissions combined from each process line at your facility using equation 3 to this paragraph (f): Equation 3 to paragraph (f) Where: N 2 2 i E N2Ot 2 i § 98.514 Monitoring and QA/QC requirements. (a) You must determine the total monthly amount of caprolactam, glyoxal, and glyoxylic acid produced. These monthly amounts are determined according to the methods in paragraph (a)(1) or (2) of this section. (1) Direct measurement of production (such as using flow meters, weigh scales, etc.). (2) Existing plant procedures used for accounting purposes ( i.e., (b) You must determine the annual amount of caprolactam, glyoxal, and glyoxylic acid produced. These annual amounts are determined by summing the respective monthly quantities determined in paragraph (a) of this section. § 98.515 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section. (a) For each missing value of caprolactam, glyoxal, or glyoxylic acid production, the substitute data must be the best available estimate based on all available process data or data used for accounting purposes (such as sales records). (b) For missing values related to the N 2 § 98.516 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (j) of this section. (a) Process line identification number. (b) Annual process N 2 (1) N 2 (2) N 2 (3) N 2 (c) Annual production quantities from all process lines at the caprolactam, glyoxal, or glyoxylic acid production facility according to paragraphs (c)(1) through (3) of this section. (1) Caprolactam production (metric tons). (2) Glyoxal production (metric tons). (3) Glyoxylic acid production (metric tons). (d) Annual production capacity from all process lines at the caprolactam, glyoxal, or glyoxylic acid production facility, as applicable, in paragraphs (d)(1) through (3) of this section. (1) Caprolactam production capacity (metric tons). (2) Glyoxal production capacity (metric tons). (3) Glyoxylic acid production capacity (metric tons). (e) Number of process lines at the caprolactam, glyoxal, or glyoxylic acid production facility, by product, in paragraphs (e)(1) through (3) of this section. (1) Total number of process lines producing caprolactam. (2) Total number of process lines producing glyoxal. (3) Total number of process lines producing glyoxylic acid. (f) Number of operating hours in the calendar year for each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (hours). (g) N 2 (h) Monthly abatement utilization factor for each N 2 (i) Number of times in the reporting year that missing data procedures were followed to measure production quantities of caprolactam, glyoxal, or glyoxylic acid (months). (j) Annual percent N 2 (1) Annual percent N 2 (2) Annual percent N 2 (3) Annual percent N 2 § 98.517 Records that must be retained. In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each caprolactam, glyoxal, or glyoxylic acid production facility: (a) Documentation of how accounting procedures were used to estimate production rate. (b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable). (c) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (4) of this section. (1) Monthly production quantity of caprolactam from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (2) Monthly production quantity of glyoxal from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (3) Monthly production quantity of glyoxylic acid from each process line at the caprolactam, glyoxal, or glyoxylic acid production facility (metric tons). (4) Destruction efficiency of N 2 2 § 98.518 Definitions. All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table 1 to Subpart YY of Part 98—N 2 Table 1 to Subpart YY of Part 98—N 2 Product N 2 a Caprolactam 9.0 Glyoxal 520 Glyoxylic acid 100 a 2 Subpart ZZ—Ceramics Manufacturing Source: 89 FR 31948, Apr. 25, 2024, unless otherwise noted. § 98.520 Definition of the source category. (a) The ceramics manufacturing source category consists of any facility that uses nonmetallic, inorganic materials, many of which are clay-based, to produce ceramic products such as bricks and roof tiles, wall and floor tiles, table and ornamental ware (household ceramics), sanitary ware, refractory products, vitrified clay pipes, expanded clay products, inorganic bonded abrasives, and technical ceramics ( e.g., (b) A ceramics manufacturing process unit is a kiln, dryer, or oven used to calcine clay or other carbonate-based materials for the production of a ceramics product. § 98.521 Reporting threshold. You must report GHG emissions under this subpart if your facility contains a ceramics manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2). § 98.522 GHGs to report. You must report: (a) CO 2 e.g., (b) CO 2 (c) CH 4 2 (d) CO 2 4 2 § 98.523 Calculating GHG emissions. You must calculate and report the annual process CO 2 (a) For each ceramics process unit that meets the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO 2 2 (b) For each ceramics process unit that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO 2 (1) For each carbonate-based raw material (including clay) charged to the ceramics process unit, either obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, or use a default value of 1.0 as the mass fraction for the raw material. (2) Determine the quantity of each carbonate-based raw material charged to the ceramics process unit. (3) Apply the appropriate emission factor for each carbonate-based raw material charged to the ceramics process unit. Table 1 to this subpart provides emission factors based on stoichiometric ratios for carbonate-based minerals. (4) Use equation 1 to this paragraph (b)(4) to calculate process mass emissions of CO 2 Equation 1 to paragraph (b)(4) Where: E CO2 2 M j j 2000/2205 = Conversion factor to convert tons to metric tons. MF i i j EF i i 2 F i i i = Index for carbonate-based mineral in each carbonate-based raw material. j = Index for carbonate-based raw material. (5) Determine the combined annual process CO 2 Equation 2 to paragraph (b)(5) CO 2 k 1 CO2 k Where: CO 2 2 E CO2 k 2 k = Total number of ceramic process units at facility. (6) Calculate and report under subpart C of this part the combustion CO 2 (c) A value of 1.0 can be used for the mass fraction (MF i j § 98.524 Monitoring and QA/QC requirements. (a) You must measure annual amounts of carbonate-based raw materials charged to each ceramics process unit from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to ceramics process units at the facility must be compared to records of raw material purchases for the year. (b) You must use the default value of 1.0 for the mass fraction of a carbonate-based mineral, or you may opt to obtain the mass fraction of any carbonate-based materials from the supplier of the raw material or by sampling the raw material. If you opt to obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, you must measure the carbonate-based mineral mass fractions at least annually to verify the mass fraction data. You may conduct the sampling and chemical analysis using any x-ray fluorescence test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards organization ( e.g., (c) You must use the default value of 1.0 for the mass fraction of a carbonate-based mineral, or you may opt to obtain the mass fraction of any carbonate-based materials from the supplier of the raw material or by sampling the raw material. If you obtain the mass fractions of any carbonate-based minerals from the supplier of the raw material or by sampling the raw material, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material at least annually by calculating an arithmetic average of the data obtained from raw material suppliers or sampling and chemical analysis. (d) You must use the default value of 1.0 for the calcination fraction of a carbonate-based mineral. Alternatively, you may opt to obtain the calcination fraction of any carbonate-based mineral by sampling. If you opt to obtain the calcination fraction of any carbonate-based minerals from sampling, you must determine on an annual basis the calcination fraction for each carbonate-based mineral consumed based on sampling and chemical analysis. You may conduct the sampling and chemical analysis using any x-ray fluorescence test, x-ray diffraction test, or other enhanced testing method published by an industry consensus standards organization ( e.g., § 98.525 Procedures for estimating missing data. A complete record of all measured parameters used in the GHG emissions calculations in § 98.523 is required. If the monitoring and quality assurance procedures in § 98.524 cannot be followed and data is unavailable, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section in the calculations. You must document and keep records of the procedures used for all such missing value estimates. (a) If the CEMS approach is used to determine combined process and combustion CO 2 (b) For missing data on the monthly amounts of carbonate-based raw materials charged to any ceramics process unit, use the best available estimate(s) of the parameter(s) based on all available process data or data used for accounting purposes, such as purchase records. (c) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials, assume that the mass fraction of a carbonate-based mineral is 1.0, which assumes that one carbonate-based mineral comprises 100 percent of the carbonate-based raw material. § 98.526 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (c) of this section, as applicable: (a) The total number of ceramics process units at the facility and the number of units that operated during the reporting year. (b) If a CEMS is used to measure CO 2 (1) The annual quantity of each carbonate-based raw material (including clay) charged to each ceramics process unit and for all units combined (tons). (2) Annual quantity of each type of ceramics product manufactured by each ceramics process unit and by all units combined (tons). (3) Annual production capacity for each ceramics process unit (tons). (c) If a CEMS is not used to measure CO 2 2 (1) Annual process emissions of CO 2 (2) The annual quantity of each carbonate-based raw material (including clay) charged to each ceramics process unit and for all units combined (tons). (3) Results of all tests used to verify each carbonate-based mineral mass fraction for each carbonate-based raw material charged to a ceramics process unit, as specified in paragraphs (c)(3)(i) through (iii) of this section. (i) Date of test. (ii) Method(s) and any variations used in the analyses. (iii) Mass fraction of each sample analyzed. (4) Method used to determine the decimal mass fraction of carbonate-based mineral, unless you used the default value of 1.0 ( e.g., (5) Annual quantity of each type of ceramics product manufactured by each ceramics process unit and by all units combined (tons). (6) Annual production capacity for each ceramics process unit (tons). (7) If you use the missing data procedures in § 98.525(b), you must report for each applicable ceramics process unit the number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials or mass fraction of the carbonate-based minerals (months). § 98.527 Records that must be retained. In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each ceramics process unit, as applicable. (a) If a CEMS is used to measure CO 2 (1) Monthly ceramics production rate for each ceramics process unit (tons). (2) Monthly amount of each carbonate-based raw material charged to each ceramics process unit (tons). (b) If process CO 2 (1) Monthly ceramics production rate for each ceramics process unit (metric tons). (2) Monthly amount of each carbonate-based raw material charged to each ceramics process unit (metric tons). (3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in equation 1 to § 98.523(b)(4), if applicable. (4) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a ceramics process unit, including the data specified in paragraphs (b)(4)(i) through (v) of this section. (i) Date of test. (ii) Method(s), and any variations of methods, used in the analyses. (iii) Mass fraction of each sample analyzed. (iv) Relevant calibration data for the instrument(s) used in the analyses. (v) Name and address of laboratory that conducted the tests. (5) Each carbonate-based mineral mass fraction for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO 2 (6) Number of annual operating hours of each ceramics process unit. (c) All other documentation used to support the reported GHG emissions. (d) The applicable verification software records as identified in this paragraph (d). You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (3) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (3) of this section. (1) Annual average decimal mass fraction of each carbonate-based mineral in each carbonate-based raw material for each ceramics process unit (specify the default value, if used, or the value determined according to § 98.524) (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.523(b)(4)). (2) Annual mass of each carbonate-based raw material charged to each ceramics process unit (tons) (equation 1 to § 98.523(b)(4)). (3) Decimal fraction of calcination achieved for each carbonate-based raw material for each ceramics process unit (specify the default value, if used, or the value determined according to § 98.524) (percent by weight, expressed as a decimal fraction) (equation 1 to § 98.523(b)(4)). § 98.528 Definitions. All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Table 1 to Subpart ZZ of Part 98—CO 2 Table 1 to Subpart ZZ of Part 98—CO 2 Carbonate Mineral name(s) CO 2 a BaCO 3 Witherite, Barium carbonate 0.223 CaCO 3 Limestone, Calcium Carbonate, Calcite, Aragonite 0.440 Ca(Fe,Mg,Mn)(CO 3 2 Ankerite b 0.408-0.476 CaMg(CO 3 2 Dolomite 0.477 FeCO 3 Siderite 0.380 K 2 3 Potassium carbonate 0.318 Li 2 3 Lithium carbonate 0.596 MgCO 3 Magnesite 0.522 MnCO 3 Rhodochrosite 0.383 Na 2 3 Sodium carbonate, Soda ash 0.415 SrCO 3 Strontium carbonate, Strontianite 0.298 a 2 b

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