Appendix B:

Greenhouse Gas Reporting Program:
Reporting Requirements

May 2023

Greenhouse Gas Reporting Program:
Reporting Requirements (as of August 16, 2018)

Subpart
Reporting Threshold
Reporting and Verification
A  - General Provisions (§98.36(g))

All in
    Except as provided in paragraph (d) of this section, each annual GHG report shall contain the following information:
    (1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited "latitude, longitude" coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point.
    (2) Year and months covered by the report.
    (3) Date of submittal.
    (4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report annual emissions of CO2, CH4, N2O, each fluorinated GHG (as defined in §98.6), and each fluorinated heat transfer fluid (as defined in §98.98) as follows.
    (i) Annual emissions (excluding biogenic CO2) aggregated for all GHG from all applicable source categories, expressed in metric tons of CO2e calculated using Equation A-1 of this subpart. For electronics manufacturing (as defined in §98.90), starting in reporting year 2012 the CO2e calculation must include each fluorinated heat transfer fluid (as defined in §98.98) whether or not it is also a fluorinated GHG.
    (ii) Annual emissions of biogenic CO2 aggregated for all applicable source categories, expressed in metric tons.
    (iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (F) of this section.
    (A) Biogenic CO2.
    (B) CO2 (excluding biogenic CO2).
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (as defined in §98.6), except fluorinated gas production facilities must comply with §98.126(a) rather than this paragraph (c)(4)(iii)(E). If a fluorinated GHG does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated GHG is a member.
    (F) For electronics manufacturing (as defined in §98.90), each fluorinated heat transfer fluid (as defined in §98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of this section. If a fluorinated heat transfer fluid does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated heat transfer fluid is a member.
    (G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the following identifying information:
    (1) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
    (2) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG or fluorinated heat transfer fluid, then report an identification number assigned by EPA's Substance Registry Services.
    (3) Linear chemical formula.
    (iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data for individual units, processes, activities, and operations as specified in the "Data reporting requirements" section of each applicable subpart of this part.
    (v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility.
    (vi) [Reserved]
    (vii) The owner or operator of a facility is not required to report the data elements specified in Table A-6 of this subpart for calendar years 2010 through 2011 until March 31, 2013. The owner or operator of a facility is not required to report the data elements specified in Table A-7 of this subpart for calendar years 2010 through 2013 until March 31, 2015 (as part of the annual report for reporting year 2014), except as otherwise specified in Table A-7 of this subpart.
    (viii) Applicable source categories means stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all of the source categories listed in Table A-3 and Table A-4 of this subpart present at the facility.
    (5) For suppliers, report annual quantities of CO2, CH4, N2O, and each fluorinated GHG (as defined in §98.6) that would be emitted from combustion or use of the products supplied, imported, and exported during the year. Calculate and report quantities at the following levels:
    (i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in Table A-5 of this subpart and expressed in metric tons of CO2e calculated using Equation A-1 of this subpart.
    (ii) Quantity of each GHG from each applicable supply category in Table A-5 to this subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the following identifying information:
    (A) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
    (B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG, then report an identification number assigned by EPA's Substance Registry Services.
    (C) Linear chemical formula.
    (iii) Any other data specified in the "Data reporting requirements" section of each applicable subpart of this part.
    (6) A written explanation, as required under §98.3(e), if you change emission calculation methodologies during the reporting period.
    (7) A brief description of each "best available monitoring method" used, the parameter measured using the method, and the time period during which the "best available monitoring method" was used, if applicable.
    (8) Each parameter for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each parameter. Parameters include not only reported data elements, but any data element required for monitoring and calculating emissions.
    (9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of §98.4(e)(1).
    (10) NAICS code(s) that apply to the facility or supplier.
    (i) Primary NAICS code. Report the NAICS code that most accurately describes the facility or supplier's primary product/activity/service. The primary product/activity/service is the principal source of revenue for the facility or supplier. A facility or supplier that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code.
    (ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the facility or supplier that are not related to the principal source of revenue.
    (11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions:
    (i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company's legal name and physical address as the United States parent company and report 100 percent ownership.
    (ii) If the facility or supplier is entirely owned by a single United States company that is, itself, owned by another company (e.g., it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership.
    (iii) If the facility or supplier is owned by more than one United States company (e.g., company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies, and report the percent ownership of each company.
    (iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative.
    (v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company's highest-level company based in the United States as the United States parent company, and report 100 percent ownership.
    (vi) If the facility or supplier is partially owned by a foreign company and partially owned by one or more U.S. companies, provide the legal name and physical address of the foreign company's highest-level company based in the United States, along with the legal names and physical addresses of the other U.S. parent companies, and report the percent ownership of each of these companies.
    (vii) If the facility or supplier is a federally owned facility, report "U.S. Government" and do not report physical address or percent ownership.
    (viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company.
    (12) For the 2010 reporting year only, facilities that have "part 75 units" (i.e. units that are subject to subpart D of this part or units that use the methods in part 75 of this chapter to quantify CO2 mass emissions in accordance with §98.33(a)(5)) must report annual GHG emissions either in full accordance with paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this section. If the latter reporting option is chosen, you must report:
    (i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO2e calculated using Equation A-1 of this subpart. You must include biogenic CO2 emissions from part 75 units in these annual emissions, but exclude biogenic CO2 emissions from any non-part 75 units and other source categories.
    (ii) Annual emissions of biogenic CO2, expressed in metric tons (excluding biogenic CO2 emissions from part 75 units), aggregated for all applicable source categories.
    (iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
    (A) Biogenic CO2 (excluding biogenic CO2 emissions from part 75 units).
    (B) CO2. You must include biogenic CO2 emissions from part 75 units in these totals and exclude biogenic CO2 emissions from other non-part 75 units and other source categories.
    (C) CH4.
    (D) N2O.
    (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.
[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]
C -- General Stationary Combustion
(§98.36)
25,000 metric tons CO2e/year
    (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. You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in §98.33(a) to calculate CO2 emissions, except as otherwise provided in paragraphs (c) and (d) of this section:
    (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., tier) used to calculate the CO2 emissions for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).
    (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 CO2 mass emissions (including biogenic CO2), and the annual CH4, and N2O mass emissions for each type of fuel combusted during the reporting year, expressed in metric tons of each gas and in metric tons of CO2e; and
    (ii) Metric tons of biogenic CO2 emissions (if applicable).
    (9) For a unit that uses Tier 4:
    (i) If the total annual CO2 mass emissions measured by the CEMS consists entirely of non-biogenic CO2 (i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent and/or process CO2), report the total annual CO2 mass emissions, expressed in metric tons. You are not required to report the combustion CO2 emissions by fuel type.
    (ii) Report the total annual CO2 mass emissions measured by the CEMS. If this total includes both biogenic and non-biogenic CO2, separately report the annual non-biogenic CO2 mass emissions and the annual CO2 mass emissions from biomass combustion, each expressed in metric tons. You are not required to report the combustion CO2 emissions by fuel type.
    (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 CH4 and N2O emissions for each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year, expressed in metric tons of each gas and in metric tons of CO2e.
    (10) Annual CO2 emissions from sorbent (if calculated using Equation C-11 of this subpart), expressed in metric tons.
    (11) If applicable, the plant code (as defined in §98.6).
    (c) Reporting alternatives for units using the four Tiers. You may use any of the applicable reporting alternatives of this paragraph to simplify the unit-level reporting required under paragraph (b) of this section:
    (1) Aggregation of units. If a facility contains two or more units (e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:
    (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 CO2 mass emissions and annual CH4, and N2O mass emissions, aggregated for each type of fuel combusted in the group of units during the report year, expressed in metric tons of each gas and in metric tons of CO2e. If any of the units burn both fossil fuels and biomass, report also the annual CO2 emissions from combustion of all fossil fuels combined and annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons.
    (vii) The methodology (i.e., tier) used to calculate the CO2 mass emissions for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or Tier 3).
    (viii) The methodology start date, for each fuel type.
    (ix) The methodology end date, for each fuel type.
    (x) The calculated CO2 mass emissions (if any) from sorbent expressed in metric tons.
    (xi) If applicable, the plant code (as defined in §98.6).
    (2) Monitored common stack or duct configurations. When the flue gases from two or more stationary fuel combustion units at a facility are combined together in a common stack or duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO2 mass emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you may report the combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG emissions from the individual units. This monitoring and reporting alternative may also be used when process off-gases or a mixture of combustion products and process gases are combined together in a common stack or duct before exiting to the atmosphere. Whenever the common stack or duct monitoring option is applied, the following information shall be reported instead of the information in paragraph (b) of this section:
    (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., a furnace, kiln, petrochemical production unit, or smelter).
    (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 CO2 mass emissions, i.e., Tier 4.
    (vi) The methodology start date.
    (vii) The methodology end date.
    (viii) Total annual CO2 mass emissions measured by the CEMS, expressed in metric tons. If any of the units burn both fossil fuels and biomass, separately report the annual non-biogenic CO2 mass emissions (i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent and/or process CO2) and the annual CO2 mass emissions from biomass combustion, each expressed in metric tons.
    (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 CH4 and N2O mass emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric tons of CO2e.
    (xi) If applicable, the plant code (as defined in §98.6).
    (3) Common pipe configurations. When two or more stationary combustion units at a facility combust the same type of liquid or gaseous fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions from the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter, or, for natural gas, the amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the flow meter shall be calibrated in accordance with §98.34(b). If a portion of the fuel measured (or obtained from gas billing records) at the main supply line is diverted to either: A flare; or another stationary fuel combustion unit (or units), including units that use a CO2 mass emissions calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used as a raw material but not combusted), and the remainder of the fuel is distributed to a group of combustion units for which you elect to use the common pipe reporting option, you may use company records to subtract out the diverted portion of the fuel from the fuel measured (or obtained from gas billing records) at the main supply line prior to performing the GHG emissions calculations for the group of units using the common pipe option. If the diverted portion of the fuel is combusted, the GHG emissions from the diverted portion shall be accounted for in accordance with the applicable provisions of this part. When the common pipe option is selected, the applicable tier shall be used based on the maximum rated heat input capacity of the largest unit served by the common pipe configuration, except where the applicable tier is based on criteria other than unit size. For example, if the maximum rated heat input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported through the common pipe is natural gas or distillate oil, in which case Tier 2 may be used, in accordance with §98.33(b)(2)(ii). As a second example, in accordance with §98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through the common pipe, if the annual fuel consumption is obtained from gas billing records in units of therms or mmBtu. When the common pipe reporting option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:
    (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 CO2 mass emissions (i.e., Tier 1, Tier 2, or Tier 3).
    (vi) If the any of the units burns both fossil fuels and biomass, the annual CO2 mass emissions from combustion of all fossil fuels and annual CO2 emissions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons.
    (vii) Annual CO2 mass emissions and annual CH4 and N2O emissions from each fuel type for the units served by the common pipe, expressed in metric tons of each gas and in metric tons of CO2e.
    (viii) Methodology start date.
    (ix) Methodology end date.
    (x) If applicable, the plant code (as defined in §98.6).
    (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. (1) For stationary combustion units that are subject to subpart D of this part, you shall report the following unit-level information:
    (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., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter.
    (ii) Annual CO2 emissions at each monitored location, expressed in both short tons and metric tons. Separate reporting of biogenic CO2 emissions under §98.3(c)(4)(ii) and §98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as provided in §98.3(c)(12).
    (iii) Annual CH4 and N2O emissions at each monitored location, for each fuel type listed in Table C-2 that was combusted during the year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
    (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 CO2 mass emissions.
    (vi) Methodology start date.
    (vii) Methodology end date.
    (viii) Acid Rain Program indicator.
    (ix) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons of CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
    (x) If applicable, the plant code (as defined in §98.6).
    (2) For units that use the alternative CO2 mass emissions calculation methods provided in §98.33(a)(5), you shall report the following unit-level information:
    (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., 1, 2, CS001, MS1A, CP001, etc.) that are reported under §75.64 of this chapter.
    (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 CO2 mass emissions for each fuel type.
    (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 CO2 emissions at each monitored location, across all fuel types, expressed in metric tons of CO2e.
    (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 CH4 and N2O emissions at each monitored location, from each fuel type listed in Table C-2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33(c)(4)(ii)(D)), expressed in metric tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
    (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 CO2 mass emissions.
    (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 CO2 emissions at each monitored location, expressed in metric tons of CO2e.
    (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 CH4 and N2O emissions at each monitored location, from each fuel type listed in Table C-2 of this subpart that was combusted during the reporting year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed in metric tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons CO2e, except where the reporting provisions of §§98.3(c)(12)(i) through (c)(12)(iii) are implemented for the 2010 reporting year.
    (J) If applicable, the plant code (as defined in §98.6).
    (e) Verification data. You must keep on file, in a format suitable for inspection and auditing, sufficient data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be included in the annual GHG emissions report.
    (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 CO2 mass emissions and heat input data year-round, in accordance with part 75 of this chapter.
    (2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in §98.33(a) to quantify CO2 emissions, the following additional information shall be kept on file and included in the GHG emissions report, where indicated:
    (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 high heat values used in the CO2 emissions calculations for each type of fuel combusted during the reporting year, in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each calendar month in which HHV determination is required. If multiple values are obtained in a given month, report the arithmetic average value for the month.
    (D) If Equation C-2c of this subpart is used to calculate CO2 mass emissions, report the total quantity (i.e., pounds) of steam produced from MSW or solid fuel combustion during each month of the reporting year, and the ratio of the maximum rate heat input capacity to the design rated steam output capacity of the unit, in mmBtu per lb of steam.
    (E) For each HHV used in the CO2 emissions calculations for each type of fuel combusted during the reporting year, indicate whether the HHV is a measured value or a substitute data value.
    (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 CH4 and N2O emissions for a Tier 3 unit, in accordance with §98.33(c)(1).
    (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 CO2 mass emissions in each quarter of the reporting year, i.e., the sum of the hourly values calculated from Equation C-6 or C-7 of this subpart (as applicable), in metric tons.
    (C) For CO2 concentration, stack gas flow rate, and (if applicable) stack gas moisture content, the percentage of source operating hours in which a substitute data value of each parameter was used in the emissions calculations.
    (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 CO2 emissions that are generated from acid gas scrubbing with sorbent injection are not captured using CEMS, report:
    (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 CO2 is determined according to §98.33(e)(2), you shall report the following additional information, as applicable:
    (A) The annual volume of CO2 emitted from the combustion of all fuels,i.e., Vtotal, in scf.
    (B) The annual volume of CO2 emitted from the combustion of fossil fuels, i.e., Vff, in scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO2 for each fuel separately as well as the total.
    (C) The annual volume of CO2 emitted from the combustion of biomass,i.e., Vbio, in scf.
    (D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in scf CO2 per mmBtu.
    (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 CO2 mass emissions, in metric tons.
    (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 CO2 emissions from MSW combustion, as described in §98.34(d), report:
    (A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions from MSW combustion is 30 percent, report 0.30).
    (B) The annual biogenic CO2 mass emissions from MSW combustion, in metric tons.
    (xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see §98.7) are used in accordance with §98.34(e) to determine the biogenic portion of the annual CO2 emissions from a unit that co-fires biogenic fuels (or partly-biogenic fuels, including tires if you are electing to report biogenic CO2 emissions from tire combustion) and non-biogenic fuels, you shall report the results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions is 30 percent, report 0.30).
    (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 CO2 emissions.
    (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 CO2 emissions.
    (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 CO2 emissions and combusts both fossil fuel and biomass.
    (v) An explanation of how company records are used to measure steam production, when it is used to calculate CO2 mass emissions under §98.33(a)(2)(iii) or to quantify solid fuel usage under §98.33(c)(3).
    (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]
D -- Electricity Generation
(§98.46)
All In
The annual report shall comply with the data reporting requirements specified in §98.36(d)(1).
[75 FR 79155, Dec. 17, 2010]
E -- Adipic Acid Production
(§98.56)
All In
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 N2O emissions from adipic acid production (metric tons).
(b)-(c) [Reserved]
(d) Annual process N2O emissions from adipic acid production facility that is sold or transferred off site (metric tons).
(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) N2O concentration per test run during performance test (ppm N2O).
(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 N2O emissions under §98.53(a)(2), each annual report must also contain the information specified in paragraphs (k)(1) through (4) of this section for each adipic acid production facility.
(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 N2O emission reduction for all production units combined.
[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]
F -- Aluminum Production
(§98.66)
All In
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 CO2-specific information for prebake cells:
(1) Annual anode consumption if using the method in §98.63(g).
(2) Annual CO2 emissions from the smelter.
(f) The following CO2-specific information for Søderberg cells:
(1) Annual paste consumption if using the method in §98.63(g).
(2) Annual CO2 emissions from the smelter.
(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]
G -- Ammonia Manufacturing
(§98.76)
All In
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 process unit.
(a) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under §98.36 for the Tier 4 Calculation Methodology and the information in paragraphs (a)(1) through (3) of this section:
(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 CO2 process emissions (metric tons) for each ammonia manufacturing process unit.
(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 CO2 emissions (metric tons) from the steam reforming of a hydrocarbon or the gasification of solid and liquid raw material at the ammonia manufacturing process unit used to produce urea and the method used to determine the CO2 consumed in urea production.
(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).
[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]
H -  Cement Production
(§98.86)
All In
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 CO2 emissions, then you must report under this subpart the relevant information required by §98.36(e)(2)(vi) and the information listed in this paragraph(a):
(1) Monthly clinker production from each kiln at the facility.
(2) Annual facility cement production.
(3) Number of kilns and number of operating kilns.
(b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in this paragraph (b) for each kiln:
(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 CO2 emission factors for each kiln (metric tons CO2/metric ton CKD produced).
(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 CO2 emission factor for the facility, averaged across all kilns (metric tons CO2/metric ton clinker produced).
(18) Annual average CKD CO2 emission factor for the facility, averaged across all kilns (metric tons CO2/metric ton CKD produced).
[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]
I -- Electronics Manufacturing
(§98.96)

25,000 metric tons CO2e/year
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) of this subpart, each fluorinated GHG emitted from each process type for which your fab is required to calculate emissions as calculated in Equations I-6 and I-7 of this subpart.
(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-8 and I-9 of this subpart, as applicable.
(3) N2O emitted from all chemical vapor deposition processes and N2O emitted from the aggregate of other N2O-using manufacturing processes as calculated in Equation I-10 of this subpart.
(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., silicon, PV-cell, glass) for each fab, including specification of the substrate.
(f)-(l) [Reserved]
(m) For the fab-specific apportioning model used to apportion fluorinated GHG and N2O consumption under §98.94(c), the following information to determine it is verified in accordance with procedures in §98.94(c)(1) and (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)-(o) [Reserved]
(p) Inventory and description of all abatement systems through which fluorinated GHGs or N2O flow at your facility and for which you are claiming destruction or removal efficiency, including:
(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 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 N2O flow at your facility, for which you are reporting controlled emissions, the following:
(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 manufacturer's recommendations and specifications for installation, operation, and maintenance for each abatement system.
(3) If you use default destruction or removal efficiency values in your emissions calculations under §98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N2O abatement, as applicable. You must support this certification by providing abatement system supplier documentation stating that the system was designed for fluorinated GHG or N2O abatement, as applicable.
(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.

View or download PDF
Where:
DREFAB = Fab-wide effective destruction or removal efficiency value, expressed as a decimal fraction.
FGHGi = Total emissions of each fluorinated GHG i emitted from electronics manufacturing processes in the fab, calculated according to the procedures in §98.93.
N2Oj = Emissions of N2O from each N2O-emitting electronics manufacturing process j in the fab, expressed in metric ton CO2 equivalents, calculated according to the procedures in §98.93.
UAFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO2 equivalents as calculated in Equation I-27 of this subpart.
SFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO2 equivalents, as calculated in Equation I-28 of this subpart.
CN2O,j = Consumption of N2O in each N2O emitting process j, expressed in metric ton CO2 equivalents.
1-UN2O,j = N2O emission factor for each N2O emitting process j from Table I-8 of this subpart.
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of this part.
GWPN2O = GWP of N2O from Table A-1 of this part.
i = Fluorinated GHG.
j = Process Type.
(1) Use Equation I-27 of this subpart to calculate total unabated emissions, in metric tons CO2e, of all fluorinated GHG emitted from electronics manufacturing processes whose emissions of fluorinated GHG you calculated according to the default utilization and by-product formation rate procedures in §98.93(a) or §98.93(i)(4). For each fluorinated GHG i in process j, use the same consumption (Cij), emission factors (1−Uij), and by-product formation rates (Bijk) to calculate unabated emissions as you used to calculate emissions in §98.93(a) or §98.93(i)(4).

View or download PDF
Where:
UAFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO2e for which you calculated total emission according to the procedures in §98.93(a) or §98.93(i)(4).
Cij = Total consumption of fluorinated GHG i, apportioned to process j, expressed in metric ton CO2e, which you used to calculate total emissions according to the procedures in §98.93(a) or §98.93(i)(4).
Uij = Process utilization rate for fluorinated GHG i, process type j, which you used to calculate total emissions according to the procedures in §98.93(a) or §98.93(i)(4).
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of this part.
GWPk = GWP of emitted fluorinated GHG by-product k from Table A-1 of this part.
Bijk = By-product formation rate of fluorinated GHG k created as a by-product per amount of fluorinated GHG input gas i (kg) consumed by process type j (kg).
i = Fluorinated GHG.
j = Process Type.
k = Fluorinated GHG by-product.
(2) Use Equation I-28 to calculate total unabated emissions, in metric ton CO2e, of all fluorinated GHG emitted from electronics manufacturing processes whose emissions of fluorinated GHG you calculated according to the stack testing procedures in §98.93(i)(3). For each set of processes, use the same input gas consumption (Cif), input gas emission factors (EFif), by-product gas emission factors (EFkf), fractions of tools abated (aif and af), and destruction efficiencies (dif and dkf) to calculate unabated emissions as you used to calculate emissions.

View or download PDF
Where:
SFGHG = Total unabated emissions of fluorinated GHG emitted from electronics manufacturing processes in the fab, expressed in metric ton CO2e for which you calculated total emission according to the procedures in §98.93(i)(3).
EFif = Emission factor for fluorinated GHG input gas i, emitted from fab f, as calculated in Equation I-19 of this subpart (kg emitted/kg input gas consumed).
aif = Fraction of fluorinated GHG input gas i used in fab f in tools with abatement systems (expressed as a decimal fraction).
dif = Fraction of fluorinated GHG i destroyed or removed in abatement systems connected to process tools in fab f, as calculated from Equation I-24A of this subpart, which you used to calculate total emissions according to the procedures in §98.93(i)(3) (expressed as a decimal fraction).
Cif = Total consumption of fluorinated GHG input gas i, of tools vented to stack systems that are tested, for fab f, for the reporting year, expressed in metric ton CO2e, which you used to calculate total emissions according to the procedures in §98.93(i)(3) (expressed as a decimal fraction).
EFkf = Emission factor for fluorinated GHG by-product gas k, emitted from fab f, as calculated in Equation I-20 of this subpart (kg emitted/kg of all input gases consumed in tools vented to stack systems that are tested).
af = Fraction of input gases used in fab f in tools with abatement systems (expressed as a decimal fraction).
dkf = Fraction of fluorinated GHG byproduct k destroyed or removed in abatement systems connected to process tools in fab f, as calculated from Equation I-24B of this subpart, which you used to calculate total emissions according to the procedures in §98.93(i)(3) (expressed as a decimal fraction).
GWPi = GWP of emitted fluorinated GHG i from Table A-1 of this part.
GWPk = GWP of emitted fluorinated GHG by-product k from Table A-1 of this part.
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. For each stack system, indicate whether the stack system is among those for which stack testing was performed as per §98.93(i)(3) or not performed as per §98.93(i)(2).
(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 CO2e basis, that are attributable to research and development activities, using the following ranges: less than 5 percent, 5 percent to less than 10 percent, 10 percent to less than 25 percent, 25 percent to less than 50 percent, 50 percent and higher.
(y) If your semiconductor manufacturing facility emits more than 40,000 metric ton CO2e of GHG emissions, based on your most recently submitted annual report (beginning with the 2015 reporting year) as required in paragraph (c) of this section, from the electronics manufacturing processes subject to reporting under this subpart, you must prepare and submit a triennial (every 3 years) technology assessment report to the Administrator (or an authorized representative) that meets the requirements specified in paragraphs (y)(1) through (6) of this section. Any other semiconductor manufacturing facility may voluntarily submit this report to the Administrator.
(1) The first report must be submitted with the annual GHG emissions report that is due no later than March 31, 2017, and subsequent reports must be delivered every 3 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 3 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 3 years that support the changes in semiconductor manufacturing processes described in the report. For any utilization or byproduct formation rate data submitted, 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. 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, and the methods used for the measurements.
(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 3-year 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]
Subpart K  -  Ferroalloy production
(§98.116)
25,000 metric tons CO2e/year
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 CO2 emissions, report the annual production for each ferroalloy product identified in §98.110, from each EAF (tons).
(c) Total number of EAFs at facility used for production of ferroalloy products.
(d) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required by §98.36 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (d)(1) through (d)(3) of this section.
(1) Annual process CO2 emissions (in metric tons) from each EAF used for the production of any ferroalloy product identified in §98.110.
(2) Annual process CH4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons).
(3) Identification number of each EAF.
(e) If a CEMS is not used to measure CO2 process emissions, and the carbon mass balance procedure is used to determine CO2 emissions according to the requirements in §98.113(b), then you must report the following information specified in paragraphs (e)(1) through (e)(7) of this section.
(1) Annual process CO2 emissions (in metric tons) from each EAF used for the production of any ferroalloy identified in §98.110 (metric tons).
(2) Annual process CH4 emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart.
(3) Identification number for each material.
(4)-(5) [Reserved]
(6) List the method used for the determination of carbon content for each material included for the calculation of annual process CO2 emissions for each EAF (e.g., supplier provided information, analyses of representative samples you collected).
(7) If you use the missing data procedures in §98.115(b), you must report how monthly mass of carbon-containing inputs and outputs with missing data was determined and the number of months the missing data procedures were used.
[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]
Subpart L  -  Fluorinated Gas Production
(§98.126)
25,000 metric tons CO2e/year
    (a) All facilities. In addition to the information required by §98.3(c), you must report the information in paragraphs (a)(2) through (6) of this section according to the schedule in paragraph (a)(1) of this section, except as otherwise provided in paragraph (j) of this section or in §98.3(c)(4)(vii) and Table A-7 of subpart A of this part.
    (1) Frequency of reporting under paragraph (a) of this section. The information in paragraphs (a)(2) through (6) of this section must be reported annually.
    (2) Generically-identified process. For each production and transformation process at the facility, you must:
    (i) Provide a number, letter, or other identifier for the process. This identifier must be consistent from year to year.
    (ii) Indicate whether the process is a fluorinated gas production process, a fluorinated gas transformation process where no fluorinated GHG reactant is produced at another facility, or a fluorinated gas transformation process where one or more fluorinated GHG reactants are produced at another facility.
    (iii) Indicate whether the process could be characterized as reaction, distillation, or packaging (include all that apply).
    (iv) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from vents (i.e., mass balance (for reporting years 2011, 2012, 2013, and 2014 only), process-vent-specific emission factor, or process-vent-specific emission calculation factor).
    (v) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from equipment leaks, unless you used the mass balance method (for reporting years 2011, 2012, 2013, and 2014 only) for that process.
    (3) Emissions from production and transformation processes, process level, multiple products. If your facility produces more than one fluorinated gas product, for each generically-identified process and each fluorinated GHG group, you must report the total GWP-weighted emissions of all fluorinated GHGs in that group from the process, in metric tons CO2e.
    (4) Emissions from production and transformation processes, facility level, multiple products. If your facility produces more than one fluorinated gas product, you must report the information in paragraphs (a)(4)(i) and (ii) of this section, as applicable, for emissions from production and transformation processes.
    (i) For each fluorinated GHG with emissions of 1,000 metric tons of CO2e or more from production and transformation processes, summed across the facility as a whole, you must report the total mass in metric tons of the fluorinated GHG emitted from production and transformation processes, summed across the facility as a whole. If the fluorinated GHG does not have a chemical-specific GWP in Table A-1 of subpart A, identify the fluorinated GHG group of which that fluorinated GHG is a member.
    (ii) For all other fluorinated GHGs emitted from production and transformation processes, you must report the total GWP-weighted emissions from production and transformation processes of those fluorinated GHGs by fluorinated GHG group, summed across the facility as a whole, in metric tons of CO2e.
    (5) Emissions from production and transformation processes, facility level, one product only. If your facility produces only one fluorinated gas product, aggregate and report the total GWP-weighted emissions from production and transformation processes of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons of CO2e, with the following exception: Where emissions consist of a major fluorinated GHG constituent of a fluorinated gas product, and the product is sold or transferred to another person, report the total mass in metric tons of each fluorinated GHG that is emitted from production and transformation processes and that is a major fluorinated GHG constituent of the product. If the fluorinated GHG does not have a chemical-specific GWP in Table A-1 of subpart A, identify the fluorinated GHG group of which that fluorinated GHG is a member.
    (6) Effective destruction efficiency. For each generically-identified process, use Table L-1 of this subpart to report the range that encompasses the effective destruction efficiency, DEeffective, calculated for that process using Equation L-35 of this subpart. The effective destruction efficiency must be reported on a CO2e basis.
    (b) Reporting for mass balance method for reporting years 2011, 2012, 2013, and 2014. If you used the mass balance method to calculate emissions for any of the reporting years 2011, 2012, 2013, or 2014, you must conduct mass balance reporting for that reporting year. For processes whose emissions were determined using the mass balance method under the former §98.123(b), as included in paragraph 1 of Appendix A of this subpart, you must report the information listed in paragraphs (b)(1) and (b)(2) of this section for each process on an annual basis.
    (1) If you calculated the relative and absolute errors under the former §98.123(b)(1), the overall absolute and relative errors calculated for the process under the former §98.123(b)(1), in metric tons CO2e and decimal fraction, respectively.
    (2) The method used to estimate the total mass of fluorine in destroyed or recaptured streams (specify the former §98.123(b)(4) or (15), as included in paragraph 1 of Appendix A of this subpart).
    (c) Reporting for emission factor and emission calculation factor approach. For processes whose emissions are determined using the emission factor approach under §98.123(c)(3) or the emission calculation factor under §98.123(c)(4), you must report the following for each generically-identified process.
    (1) [Reserved]
    (2) [Reserved]
    (3) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from all process vents combined, in metric tons of CO2e.
    (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 CO2e.
    (d) Reporting for missing data. Where missing data have been estimated pursuant to §98.125, you must report:
    (1) The generically-identified process for which the data were missing.
    (2) The reason the data were missing, the length of time the data were missing, and the method used to estimate the missing data.
    (3) Estimates of the missing data for all missing data associated with data elements required to be reported in this section.
    (e) Reporting of destruction device excess emissions data. Each fluorinated gas production facility that destroys fluorinated GHGs must report the excess emissions that result from malfunctions of the destruction device, and these excess emissions must be reflected in the fluorinated GHG estimates in the former §98.123(b) as included in paragraph 1 of Appendix A of this subpart for the former mass balance method, and in §98.123(c). Such excess emissions would occur if the destruction efficiency was reduced due to the malfunction.
    (f) Reporting of destruction device testing. By March 31, 2012 or by March 31 of the year immediately following the year in which it begins fluorinated GHG destruction, each fluorinated gas production facility that destroys fluorinated GHGs must submit a report containing the information in paragraphs (f)(1) through (f)(4) of this section. This report is one-time unless you make a change to the destruction device that would be expected to affect its destruction efficiencies.
    (1) [Reserved]
    (2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate the destruction efficiency for each fluorinated GHG, consistent with requirements in §98.124(g)(1), vented to the destruction device.
    (3) Date of the most recent destruction device test.
    (4) Name of all applicable Federal or State regulations that may apply to the destruction process.
    (5) [Reserved]
    (g) Reporting for destruction of previously produced fluorinated GHGs. Each fluorinated gas production facility that destroys fluorinated GHGs must report, separately from the fluorinated GHG emissions reported under paragraphs (b) or (c) of this section, the following for each previously produced fluorinated GHG destroyed:
    (1) [Reserved]
    (2) The mass of the fluorinated GHG emitted from the destruction device (metric tons).
    (h) Reporting of emissions from venting of residual fluorinated GHGs from containers. Each fluorinated gas production facility that vents residual fluorinated GHGs from containers must report the following for each fluorinated GHG vented:
    (1) The mass of the residual fluorinated GHG vented from containers annually (metric tons).
    (2) [Reserved]
    (i) Reporting of fluorinated GHG products of incomplete combustion (PICs) of fluorinated gases. Each fluorinated gas production facility that destroys fluorinated gases must submit a one-time report by June 30, 2011, that describes any measurements, research, or analysis that it has performed or obtained that relate to the formation of products of incomplete combustion that are fluorinated GHGs during the destruction of fluorinated gases. The report must include the methods and results of any measurement or modeling studies, including the products of incomplete combustion for which the exhaust stream was analyzed, as well as copies of relevant scientific papers, if available, or citations of the papers, if they are not. No new testing is required to fulfill this requirement.
    (j) Special provisions for reporting years 2011, 2012, and 2013 only. For reporting years 2011, 2012, and 2013, the owner or operator of a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of this section.
    (1) Timing. The owner or operator of a facility is not required to report the data elements at §98.3(c)(4)(iii) and paragraphs (a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section until the later of March 31, 2015 or the date set forth for that data element at §98.3(c)(4)(vii) and Table A-7 of Subpart A of this part.
    (2) Excess emissions. Excess emissions of fluorinated GHGs resulting from destruction device malfunctions must be reflected in the reported facility-wide CO2e emissions but are not required to be reported separately.
    (3) Calculation and reporting of CO2e. You must report the total fluorinated GHG emissions covered by this subpart, expressed in metric tons of CO2e. This includes emissions from all fluorinated gas production processes, all fluorinated gas transformation processes that are not part of a fluorinated gas production process, all fluorinated gas destruction processes that are not part of a fluorinated gas production process or a fluorinated gas transformation process, and venting of residual fluorinated GHGs from containers returned from the field. To convert fluorinated GHG emissions to CO2e for reporting under this section, use Equation A-1 of §98.2. For fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use either the default GWP specified below or your best estimate of the GWP based on the information described in §98.123(c)(1)(vi)(A)(3). Use of quantitative structure activity relationships (QSARs) is an acceptable method for determining GWPs in situations where pure standards of the "target" fluorinated GHG are not available, the "target" fluorinated GHG cannot be isolated from gas streams, and FTIR spectra for the impurities are not available.
    (i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs.
    (ii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO2e, that were calculated using the default GWP of 2000.
    (iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO2e, that were calculated using the default GWP of 10,000.
    (iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO2e, that were calculated using your best estimate of the GWP.
    (k) Submission of complete reporting year 2011, 2012, and 2013 GHG reports. By March 31, 2015, you must submit annual GHG reports for reporting years 2011, 2012, and 2013 that contain the information specified in paragraphs (a) through (i) of this section. The reports must calculate CO2e using the GWPs in Table A-1 of subpart A of this part (as in effect on January 1, 2015). Prior submission of partial reports for these reporting years under paragraph (j) of this section does not affect your obligation to submit complete reports under this paragraph.
[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]
Subpart N  -  Glass Production
(§98.146)
25,000 metric tons CO2e/year
    In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required under §98.36 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (2) of this section:
    (1) Annual quantity of each carbonate-based raw material charged to each continuous glass melting furnace and for all furnaces combined (tons).
    (2) Annual quantity of glass produced by each glass melting furnace and by all furnaces combined (tons).
    (b) If a CEMS is not used to determine CO2 emissions from continuous glass melting furnaces, and process CO2 emissions are calculated according to the procedures specified in §98.143(b), then you must report the following information as specified in paragraphs (b)(1) through (b)(9) of this section:
    (1) Annual process emissions of CO2 (metric tons) for each continuous glass melting furnace and for all furnaces combined.
    (2) Annual quantity of each carbonate-based raw material charged (tons) to all furnaces combined.
    (3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined.
    (4) [Reserved]
    (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 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]
Subpart O  -  HCFC-22 Production and HFC-23 Destruction
(§98.156)
HCFC-22: All In

HFC-23 destruction processes that are not collocated with a HCFC-22 production and that destroy more than 2.14 metric tons HFC-23 per year: All In

    (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]
Subpart P  -  Hydrogen Production
(§98.166)
25,000 metric tons CO2e/year
    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, and paragraphs (c) through (e) of this section:
    (a) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under §98.36 for the Tier 4 Calculation Methodology and the following information in this paragraph (a):
    (1) Unit identification number and annual CO2 emissions.
    (2) Annual quantity of hydrogen produced (metric tons) for each process unit.
    (3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit.
    (b) If a CEMS is not used to measure CO2 emissions, then you must report the following information for each hydrogen production process unit:
    (1) Unit identification number and annual CO2 emissions.
    (2) [Reserved]
    (3) Annual quantity of hydrogen produced (metric tons).
    (4) Annual quantity of ammonia produced, if applicable (metric tons).
    (5)-(6) [Reserved]
    (7) Name and annual quantity (metric tons) of each carbon-containing fuel and feedstock.
    (c) Quantity of CO2 collected and transferred off site in either gas, liquid, or solid forms, following the requirements of subpart PP of this part.
    (d) Annual quantity of carbon other than CO2 collected and transferred off site in either gas, liquid, or solid forms (kg carbon).
    (e) Annual methanol production (metric tons) for each process unit.
[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 66463, Oct. 28, 2010; 78 FR 71955, Nov. 29, 2013; 79 FR 63787, Oct. 24, 2014]
Subpart Q  -  Iron and Steel Production
(§98.176)
25,000 metric tons CO2e/year
    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 CO2 emissions (in metric tons).
    (b) If a CEMS is used to measure CO2 emissions, then you must report the annual production quantity for the production unit (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel.
    (c) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under §98.36 for the Tier 4 Calculation Methodology.
    (d) If a CEMS is not used to measure CO2 emissions, then you must report for each process whether the emissions were determined using the carbon mass balance method in §98.173(b)(1) or the site-specific emission factor method in §98.173(b)(2).
    (e) If you use the carbon mass balance method in §98.173(b)(1) to determine CO2 emissions, you must, except as provided in §98.174(b)(4), report the following information for each process:
    (1) [Reserved]
    (2) Whether the carbon content was determined from information from the supplier or by laboratory analysis, and if by laboratory analysis, the method used.
    (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 CO2 emissions were determined using the mass balance method in §98.173(b)(1), except as provided in §98.174(b)(4).
    (i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used in process units for which CO2 emissions were determined using Equations Q-1 through Q-7 of §98.173, calculated as specified in Equation Q-9 of this section.

    View or download PDF
    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.
    Fg,i = Annual volume of gaseous fuel combusted ("(Fg)" in Equations Q-1, Q-4 and Q-7 of §98.173) for each process (scf).
    MWi = Molecular weight of gaseous fuel used in each process (kg/kg-mole).
    MVC = Molar volume conversion factor at standard conditions, as defined in §98.6. Use 849.5 scf per kg mole if you select 68 °F as standard temperature and 836.6 scf per kg mole if you select 60 °F as standard temperature.
    Fl,i = Annual volume of the liquid fuel combusted ("(Fl)" included in Equation Q-1) for each process unit (gallons).
    Fs,i = Annual mass of the solid fuel combusted ("(Fs)" in Equation Q-1) for each process unit (metric tons).
    ρl,i = Density of the liquid fuel (kg/gallon).
    0.001 = Conversion factor from kg to metric tons.
    (ii) The annual mass (metric tons) of all non-fuel material inputs (combined) specified in Equations Q-1 through Q-7 of §98.173, calculated as specified in Equation Q-10 of this section.

    View or download PDF
    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).
    Steelin = Annual mass of molten steel charged to the decarburization vessels (metric tons).
    Ore = Annual mass of iron ore or iron ore pellets fed to the direct reduction furnace(s) (metric tons).
    Other = Annual mass of other materials charged to the direction reduction furnace(s) (metric tons).
    (iii) The annual mass (metric tons) of all solid and liquid products and byproducts (combined) specified in Equations Q-1 through Q-7 of §98.173, calculated as specified in Equation Q-11 of this section.

    View or download PDF
    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).
    Steelout = Annual mass of steel produced by the basic oxygen furnace(s), EAF(s) and decarburization vessel(s) (metric tons).
    Slag = Annual mass of slag produced by the basic oxygen furnace(s) and EAF(s) (metric tons).
    Coke = Annual mass of coke produced by the non-recovery coke batteries (metric tons).
    Sinter = Annual mass of sinter produced from the sinter process(es) (metric tons).
    Iron = Annual mass of iron produced from the direct reduction furnace (metric tons).
    NM = Annual mass of non-metallic materials produced by the direct reduction furnace (metric tons).
    (iv) The weighted average carbon content of all gaseous, liquid, and solid fuels (combined) included in Equation Q-9 of this section, calculated as specified in Equation Q-12 of this section.

    View or download PDF
    Where:
    CFavg = Weighted average carbon content of all gaseous, liquid, and solid fuels included in Equation Q-9 of this section (weight fraction).
    n = Number of gaseous, liquid, and solid fuel inputs to each process unit as used in Equation Q-9 of this section.
    Cgf,i = Average carbon content of the gaseous fuel used in each process, from the fuel analysis results (kg C per kg of fuel).
    Clf,i = Carbon content of the liquid fuel used in each process, from the fuel analysis results (kg C per gallon of fuel.
    Csf = Carbon content of the solid fuel used in each process, from the fuel analysis (expressed as a decimal fraction, e.g., 95% = 0.95).
    Fuel = Annual mass of all gaseous, liquid, and solid fuels used in process units (metric tons), as calculated in Equation Q-9.
    (v) The weighted average carbon content of all non-fuel inputs to all process units (combined) included in Equation Q-10 of this section, calculated as specified in Equation Q-13 of this section.

    View or download PDF
    Where:
    CIavg = Weighted average carbon content of all non-fuel inputs to all process units included in Equation Q-10 of this section (weight fraction).
    n = Number of non-fuel inputs to all process units as used in Equation Q-10.
    NFIi = Annual mass of each non-fuel input used in Equation Q-10 (metric tons).
    CNFIi = Average carbon content of each non-fuel input used in Equation Q-10 (expressed as a decimal fraction).
    NFI = Total of all non-fuel inputs to all process units (metric tons).
    (vi) The weighted average carbon content of all solid and liquid products and byproducts from all process units (combined) included in Equation Q-11 of this section, calculated as specified in Equation Q-14 of this section.

    View or download PDF
    Where:
    CPavg = Weighted average carbon content of all solid and liquid products and byproducts from all process units (weight fraction).
    n = Number of products and byproducts from each process unit as used in Equation Q-11 of this section.
    Producti = Annual mass of each product or byproduct used in Equation Q-11 (metric tons).
    Cp,i = Average carbon content of each product or byproduct used in Equation Q-11 (expressed as a decimal fraction).
    Products = Mass of all products and byproducts from all process units, calculated in Equation Q-11 (metric tons).
    (f) If you used the site-specific emission factor method in §98.173(b)(2) to determine CO2 emissions, you must report the following information for each process:
    (1) The measured average hourly CO2 emission rate during the test (in metric tons per hour).
    (2)-(4) [Reserved]
    (g) [Reserved]
    (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]
Subpart R  -  Lead Production
(§98.186)
25,000 metric tons CO2e/year
    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 CO2 emissions according to the requirements in §98.183(a) or (b)(1), then you must report under this subpart the relevant information required by §98.36 and the information specified in paragraphs (a)(1) through (a)(4) of this section.
    (1) Identification number of each smelting furnace.
    (2) Annual lead product production capacity (tons).
    (3) Annual production for each lead product (tons).
    (4) Total number of smelting furnaces at facility used for lead production.
    (b) If a CEMS is not used to measure CO2 emissions, and you measure CO2 emissions according to the requirements in §98.183(b)(2)(i) and (b)(2)(ii), then you must report the information specified in paragraphs (b)(1) through (b)(9) of this section.
    (1) Identification number of each smelting furnace. (2) Annual process CO2 emissions (in metric tons) from each smelting furnace as determined by Equation R-1 of this subpart.
    (3) Annual lead product production capacity for the facility and each smelting furnace(tons).
    (4) Annual production for each lead product (tons).
    (5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of this section.
    (6)-(7) [Reserved]
    (8) List the method used for the determination of carbon content for each material used for the calculation of annual process CO2 emissions using Equation R-1 of §98.183 for each smelting furnace (e.g., supplier provided information, analyses of representative samples you collected).
    (9) If you use the missing data procedures in §98.185(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
    [74 FR 56374, Oct. 30, 2009, as amended at 79 FR 63792, Oct. 24, 2014]
Subpart S  -  Lime Production
(§98.196)
All In
    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 CO2 emissions, then you must report under this subpart the relevant information required by §98.36 and the information listed in paragraphs (a)(1) through (8) of this section.
    (1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold.
    (2) Method used to determine the quantity of calcined lime byproduct or waste sold.
    (3) Beginning and end of year inventories for each lime product that is produced, by type.
    (4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type.
    (5) Annual amount of calcined lime byproduct or waste sold, by type (tons).
    (6) Annual amount of lime product sold, by type (tons).
    (7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons).
    (8) Annual amount of lime product not sold, by type (tons).
    (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in paragraphs (b)(1) through (21) of this section.
    (1) Annual CO2 process emissions from all lime kilns combined (metric tons).
    (2)-(3) [Reserved]
    (4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type.
    (5)-(6) [Reserved]
    (7) Method used to determine the quantity of lime produced and/or lime sold.
    (8) [Reserved]
    (9) Method used to determine the quantity of calcined lime byproduct or waste sold.
    (10)-(12) [Reserved]
    (13) Beginning and end of year inventories for each lime product that is produced.
    (14) Beginning and end of year inventories for calcined lime byproducts or wastes sold.
    (15) Annual lime production capacity (tons) per facility.
    (16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months).
    (17) Indicate whether CO2 was used on-site (i.e. for use in a purification process). If CO2 was used on-site, provide the information in paragraphs (b)(17)(i) and (ii) of this section.
    (i) The annual amount of CO2 captured for use in the on-site process.
    (ii) The method used to determine the amount of CO2 captured.
    (18) Annual quantity (tons) of lime product sold, by type.
    (19) Annual average emission factors for each lime product type produced.
    (20) Annual average emission factors for each calcined byproduct/waste by lime type that is sold.
    (21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold.
    [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]
Subpart T  -  Magnesium Production
(§98.206)
25,000 metric tons CO2e/year
    In addition to the information required by §98.3(c), each annual report must include the following information at the facility level:
    (a) Emissions of each cover or carrier gas in metric tons.
    (b) Types of production processes at the facility (e.g., primary, secondary, die casting).
    (c) Amount of magnesium produced or processed in metric tons for each process type. This includes the output of primary and secondary magnesium production processes and the input to magnesium casting processes.
    (d) Cover and carrier gas flow rate (e.g., standard cubic feet per minute) for each production unit and composition in percent by volume.
    (e) For any missing data, you must report the length of time the data were missing for each cover gas or carrier gas, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
    (f) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg).
    (g) If applicable, an explanation of any change greater than 30 percent in the facility's cover gas usage rate (e.g., installation of new melt protection technology or leak discovered in the cover gas delivery system that resulted in increased emissions).
    (h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year.
Subpart U  -  Miscellaneous Uses of Carbonate
(§98.216)
25,000 metric tons CO2e/year
    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 CO2 emissions from miscellaneous carbonate use (metric tons).
    (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]
Subpart V  -  Nitric Acid Production
(§98.226)
All In
    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 N2O emissions from each nitric acid train (metric tons).
    (c) [Reserved]
    (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 N2O abatement technologies per nitric acid train "t".
    (h) Abatement technologies used (if applicable).
    (i) [Reserved]
    (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 N2O emissions under §98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (4) of this section.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.
    (o) [Reserved]
    (p) [Reserved]
    (q) Annual percent N2O emission reduction for all nitric acid trains combined.
    [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]
Subpart W  -  Petroleum and Natural Gas Systems
(§98.236)
25,000 metric tons CO2e/year
    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 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), and each applicable emission source listed in paragraphs (b) through (z) of this section.
    (1) Onshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(1)(i) through (xvii) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) of this section.
    (v) Liquids unloading. Report the information specified in paragraph (f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report the information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing. Report the information specified in paragraph (h) of this section.
    (viii) Onshore production storage tanks. Report the information specified in paragraph (j) of this section.
    (ix) Well testing. Report the information specified in paragraph (l) of this section.
    (x) Associated natural gas. Report the information specified in paragraph (m) of this section.
    (xi) Flare stacks. Report the information specified in paragraph (n) of this section.
    (xii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (xiii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (xiv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (xv) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (xvi) EOR injection pumps. Report the information specified in paragraph (w) of this section.
    (xvii) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this section.
    (xviii) Combustion equipment. Report the information specified in paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section.
    (3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Acid gas removal units. Report the information specified in paragraph (d) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) of this section.
    (iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
    (iv) Flare stacks. Report the information specified in paragraph (n) of this section.
    (v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (4) Onshore natural gas transmission compression. For the equipment/activities specified in paragraphs (a)(4)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
    (iii) Transmission storage tanks. Report the information specified in paragraph (k) of this section.
    (iv) Flare stacks. Report the information specified in paragraph (n) of this section.
    (v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
    (ii) Flare stacks. Report the information specified in paragraph (n) of this section.
    (iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (v) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Flare stacks. Report the information specified in paragraph (n) of this section.
    (ii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (iii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (iv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (v) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
    (ii) Flare stacks. Report the information specified in paragraph (n) of this section.
    (iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (iii) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Combustion equipment. Report the information specified in paragraph (z) of this section.
    (ii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (iii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (9) Onshore petroleum and natural gas gathering and boosting. For the equipment/activities specified in paragraphs (a)(9)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) of this section.
    (v) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
    (vi) Storage tanks. Report the information specified in paragraph (j) of this section.
    (vii) Flare stacks. Report the information specified in paragraph (n) of this section.
    (viii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
    (ix) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
    (x) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
    (xi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
    (xii) Combustion equipment. Report the information specified in paragraph (z) of this section.
    (10) Onshore natural gas transmission pipeline. For blowdown vent stacks, report the information specified in paragraph (i) of this section.
    (b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(4) of this section.
    (1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (ii) of this section.
    (i) The total number of devices of each type, determined according to §98.233(a)(1) and (2).
    (ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined according to §98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) through (C) of this section.
    (A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are counted.
    (B) The number of devices of each type reported in paragraph (b)(1)(i) 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.
    (2) For each type of pneumatic device, the estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year ("Tt" in Equation W-1 of this subpart).
    (3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices combined, calculated using Equation W-1 of this subpart and §98.233(a)(4), and reported in paragraph (b)(1)(i) of this section.
    (4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices combined, calculated using Equation W-1 of this subpart and §98.233(a)(4), and reported in paragraph (b)(1)(i) of this section.
    (c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (4) of this section.
    (1) Count of natural gas driven pneumatic pumps.
    (2) Average estimated number of hours in the calendar year the pumps were operational ("T" in Equation W-2 of this subpart).
    (3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic pumps combined, calculated according to §98.233(c)(1) and (2).
    (4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic pumps combined, calculated according to §98.233(c)(1) and (2).
    (d) Acid gas removal units. You must indicate whether your facility has any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the information specified in paragraphs (d)(1) and (2) of this section.
    (1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of this section for each acid gas removal unit.
    (i) A unique name or ID number for the acid gas 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 for each location it operates at in a given year.
    (ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year.
    (iii) The calculation method used to calculate CO2 emissions from the acid gas removal unit, as specified in §98.233(d).
    (iv) Whether any CO2 emissions from the acid gas removal unit are recovered and transferred outside the facility, as specified in §98.233(d)(11). If any CO2 emissions from the acid gas removal unit were recovered and transferred outside the facility, then you must report the annual quantity of CO2, in metric tons CO2, that was recovered and transferred outside the facility under subpart PP of this part.
    (v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, calculated using any one of the calculation methods specified in §98.233(d) and as specified in §98.233(d)(10) and (11).
    (vi) Sub-basin ID that best represents the wells supplying gas to the unit (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the unit (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.
    (i) If you used Calculation Method 1 or Calculation Method 2 as specified in §98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(i)(A) and (B) of this section.
    (A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas removal unit.
    (B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.
    (ii) If you used Calculation Method 3 as specified in §98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (D) of this section.
    (A) Indicate which equation was used (Equation W-4A or W-4B).
    (B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the acid gas removal unit, as specified in Equation W-4A or Equation W-4B of this subpart.