(A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring.
    (B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere.
    (C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere.
    (xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (D) of this section.
    (A) The number of atmospheric tanks that controlled emissions with flares.
    (B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with one or more flares.
    (C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with one or more flares.
    (D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with one or more flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.
    (i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3.
    (A) The total annual oil throughput that is sent to all atmospheric tanks in the basin, in barrels. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil production less than 10 barrels per day and that send oil to atmospheric tanks. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the total annual oil throughput from all wells and the API Well Number(s) for the well(s) included in this volume.
    (B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with flares.
    (C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems.
    (D) The number of atmospheric tanks in the basin.
    (E) The number of wells with gas-liquid separators ("Count" from Equation W-15 of this subpart) in the basin.
    (F) The number of wells without gas-liquid separators ("Count" from Equation W-15 of this subpart) in the basin.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each sub-basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that did not control emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that did not control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the sub-basin that did not control emissions with flares, calculated using Equation W-15 of this subpart and adjusted for vapor recovery, if applicable.
    (D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the sub-basin that did not control emissions with flares, calculated using Equation W-15 of this subpart and adjusted for vapor recovery, if applicable.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) of this section for each sub-basin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that controlled emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that controlled emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with flares.
    (D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with flares.
    (E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with flares.
    (3) If you used Calculation Method 1 or Calculation Method 2, and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (iv) of this section for each sub-basin.
    (i) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year.
    (ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the "Tn" values used in Equation W-16 of this subpart).
    (iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on gas-liquid separators not closing properly during the calendar year, calculated using Equation W-16 of this subpart.
    (iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves on gas-liquid separators not closing properly during the calendar year, calculated using Equation W-16 of this subpart.
    (k) Transmission storage tanks. You must indicate whether your facility contains any transmission storage tanks. If your facility contains at least one transmission storage tank, then you must report the information specified in paragraphs (k)(1) through (3) of this section for each transmission storage tank vent stack.
    (1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section.
    (i) The unique name or ID number for the transmission storage tank vent stack.
    (ii) Method used to determine if dump valve leakage occurred.
    (iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to §98.233(k)(2).
    (iv) Indicate if there is a flare attached to the transmission storage tank vent stack.
    (2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred.
    (i) Method used to measure the leak rate.
    (ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.
    (iii) Duration of time that the leak is counted as having occurred, in hours, as determined in §98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere, calculated according to §98.233(k)(1) through (4).
    (v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere, calculated according to §98.233(k)(1) through (4).
    (3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (vi) of this section.
    (i) Method used to measure the leak rate.
    (ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.
    (iii) Duration of time that flaring occurred in hours, as defined in §98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, calculated according to §98.233(k)(5).
    (v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, calculated according to §98.233(k)(5).
    (vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, calculated according to §98.233(k)(5).
    (l) Well testing. You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (4) of this section, as applicable.
    (1) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (vi) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured average flow rate for well(s) tested and the API Well Number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).
    (vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).
    (2) If you used Equation W-17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (vii) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) tested in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured average flow rate for well(s) tested and the API Well Number(s) for the well(s) included in the measurement.
    (v) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).
    (vi) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).
    (vii) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).
    (3) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (v) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days per well for well(s) tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured average annual production rate for well(s) tested and the API Well Number(s) for the well(s) included in the measurement.
    (iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).
    (4) If you used Equation W-17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (vi) of this section.
    (i) Number of wells tested in calendar year.
    (ii) Average number of well testing days per well for well(s) tested in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured average annual production rate for well(s) tested and the API Well Number(s) for the well(s) included in the measurement.
    (iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(l).
    (vi) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(l).
    (m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented or flared during the calendar year, then you must report the information specified in paragraphs (m)(1) through (8) of this section for each sub-basin.
    (1) Sub-basin ID.
    (2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.
    (3) Indicate whether any associated gas was flared.
    (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the "GOR" values used in Equation W-18 of this subpart).
    (5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of "Vp,q" used in Equation W-18 of this subpart). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the volume of oil produced for well(s) with associated gas venting and flaring and the API Well Number(s) for the well(s) included in the measurement.
    (6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of "SG" values used in Equation W-18 of §98.233(m)). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in §98.236(cc) the measured total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the API Well Number(s) for the well(s) included in the measurement.
    (7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (iii) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring.
    (ii) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(m)(3) and (4).
    (iii) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(m)(3) and (4).
    (8) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)(8)(i) through (iv) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared.
    (ii) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(m)(5).
    (iii) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(m)(5).
    (iv) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility contains any flare stacks. You must report the information specified in paragraphs (n)(1) through (12) of this section for each flare stack at your facility, and for each industry segment applicable to your facility.
    (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year.
    (2) Indicate whether the flare stack has a continuous flow measurement device.
    (3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare.
    (4) Volume of gas sent to the flare, in standard cubic feet ("Vs" in Equations W-19 and W-20 of this subpart).
    (5) Fraction of the feed gas sent to an un-lit flare ("Zu" in Equation W-19 of this subpart).
    (6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare.
    (7) Mole fraction of CH4 in the feed gas to the flare ("XCH4" in Equation W-19 of this subpart).
    (8) Mole fraction of CO2 in the feed gas to the flare ("XCO2" in Equation W-20 of this subpart).
    (9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W-20 of this subpart).
    (10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W-19 of this subpart).
    (11) Annual N2O emissions, in metric tons N2O (refer to Equation W-40 of this subpart).
    (12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N2O and CH4 emissions for the flare stack.
    (o) Centrifugal compressors. You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in §98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in §98.233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (o)(1) through (4) of this section and instead must report the information specified in paragraph (o)(5) of this section.
    (1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal compressor located at your facility.
    (i) Unique name or ID for the centrifugal compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in not-operating-depressurized-mode.
    (iv) Indicate whether the compressor was measured in operating-mode.
    (v) Indicate whether the compressor was measured in not-operating-depressurized-mode.
    (vi) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
    (vii) Indicate which, if any, compressor sources are routed to a flare.
    (viii) Indicate which, if any, compressor sources have vapor recovery.
    (ix) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
    (x) Indicate whether the compressor has blind flanges installed and associated dates.
    (xi) Indicate whether the compressor has wet or dry seals.
    (xii) If the compressor has wet seals, the number of wet seals.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i)(A) through (C) of this section.
    (A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section.
    (B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).
    (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in §98.233(o)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in §98.233(o)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery, you are not required to report emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
    (3) As found measurement sample data. If the measurement methods specified in §98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the calculation specified in §98.233(o)(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-23 was used to calculate emissions in Equation W-22, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EFs,m in Equation W-23).
    (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Countm in Equation W-23).
    (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods specified in §98.233(o)(3) or (5) are conducted, report the information specified in paragraphs (o)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in §98.233(o)(3)(ii) and (o)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production must report the information specified in paragraphs (o)(5)(i) through (iii) of this section.
    (i) Number of centrifugal compressors that have wet seal oil degassing vents.
    (ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with wet seal oil degassing vents.
    (iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with wet seal oil degassing vents.
    (p) Reciprocating compressors. You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in §98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in §98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (p)(1) through (4) of this section and instead must report the information specified in paragraph (p)(5) of this section.
    (1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (xiv) of this section for each reciprocating compressor located at your facility.
    (i) Unique name or ID for the reciprocating compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in standby-pressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) Indicate whether the compressor was measured in operating-mode.
    (vi) Indicate whether the compressor was measured in standby-pressurized-mode.
    (vii) Indicate whether the compressor was measured in not-operating-depressurized-mode.
    (viii) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
    (ix) Indicate which, if any, compressor sources are routed to a flare.
    (x) Indicate which, if any, compressor sources have vapor recovery.
    (xi) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
    (xii) Indicate whether the compressor has blind flanges installed and associated dates.
    (xiii) Power output of the compressor driver (hp).
    (xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
    (2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i)(A) through (C) of this section.
    (A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.
    (B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).
    (C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
    (ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.
    (A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
    (B) Indicate whether an as found measurement(s) as identified in §98.233(p)(2) or (4) was conducted on the leak or vent.
    (C) Indicate whether continuous measurements as identified in §98.233(p)(3) or (5) were conducted on the leak or vent.
    (D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to flare, combustion, or vapor recovery, you are not required to report emissions under this paragraph.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
    (3) As found measurement sample data. If the measurement methods specified in §98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the calculation specified in §98.233(p)(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this section.
    (i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section.
    (A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
    (B) Measurement date.
    (C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
    (F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
    (ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-28 was used to calculate emissions in Equation W-27, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EFs,m in Equation W-28).
    (C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Countm in Equation W-28).
    (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter's applicable facilities.
    (4) Continuous measurement data. If the measurement methods specified in §98.233(p)(3) or (5) are conducted, report the information specified in paragraphs (p)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
    (i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
    (ii) Measured volume of flow during the reporting year, in million standard cubic feet.
    (iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in §98.233(p)(3)(ii) and (p)(5)(iii).
    (iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
    (5) Onshore petroleum and natural gas production. Reciprocating compressors in onshore petroleum and natural gas production must report the information specified in paragraphs (p)(5)(i) through (iii) of this section.
    (i) Number of reciprocating compressors.
    (ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors.
    (iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors.
    (q) Equipment leak surveys. If your facility is subject to the requirements of §98.233(q), then you must report the information specified in paragraphs (q)(1) and (2) of this section. Natural gas distribution facilities with emission sources listed in §98.232(i)(1) must also report the information specified in paragraph (q)(3) of this section.
    (1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this section.
    (i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete equipment leak surveys performed during the calendar year.
    (ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle.
    (2) You must indicate whether your facility contains any of the component types listed in §98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility's industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of this section but report a zero ("0") for the information required according to paragraphs (q)(2)(iii), (iv), and (v) of this section.
    (i) Component type.
    (ii) Total number of the surveyed component type that were identified as leaking in the calendar year ("xp" in Equation W-30 of this subpart for the component type).
    (iii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of "Tp,z" from Equation W-30 of this subpart for the component type).
    (iv) Annual CO2 emissions, in metric tons CO2, for the component type as calculated using Equation W-30 (for surveyed components only).
    (v) Annual CH4 emissions, in metric tons CH4, for the component type as calculated using Equation W-30 (for surveyed components only).
    (3) Natural gas distribution facilities with emission sources listed in §98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.
    (i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.
    (ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year ("CountMR,y" from Equation W-31 of this subpart, for the current calendar year).
    (iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of "Tw,y" from Equation W-31 of this subpart, for the current calendar year).
    (iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle.
    (v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of "CountMR,y" from Equation W-31 of this subpart, for all calendar years in the current leak survey cycle).
    (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of "Tw,y" from Equation W-31 of this subpart, for all years included in the leak survey cycle).
    (vii) Meter/regulator run CO2 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO2 per operational hour of all meter/regulator runs ("EFs,MR,i" for CO2calculated using Equation W-31 of this subpart).
    (viii) Meter/regulator run CH4 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH4 per operational hour of all meter/regulator runs ("EFs,MR,i" for CH4calculated using Equation W-31 of this subpart).
    (ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report:
    (A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility ("CountMR" in Equation W-32B of this subpart).
    (B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run ("Tw,avg" in Equation W-32B of this subpart).
    (C) Annual CO2 emissions, in metric tons CO2, for all above grade transmission-distribution transfer stations at your facility.
    (D) Annual CH4 emissions, in metric tons CH4, for all above grade transmission-distribution transfer stations at your facility.
    (r) Equipment leaks by population count. If your facility is subject to the requirements of §98.233(r), then you must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable.
    (1) You must indicate whether your facility contains any of the emission source types required to use Equation W-32A of this subpart. You must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately for each emission source type required to use Equation W-32A of this subpart that is located at your facility. Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately by component type, service type, and geographic location (i.e., Eastern U.S. or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas production facilities must report the component type, service type and geographic location.
    (ii) Total number of the emission source type at the facility ("Counte" in Equation W-32A of this subpart).
    (iii) Average estimated time that the emission source type was operational in the calendar year, in hours ("Te" in Equation W-32A of this subpart).
    (iv) Annual CO2 emissions, in metric tons CO2, for the emission source type.
    (v) Annual CH4 emissions, in metric tons CH4, for the emission source type.
    (2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section.
    (i) Number of above grade transmission-distribution transfer stations at the facility.
    (ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility.
    (iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations ("CountMR" in Equation W-32B of this subpart).
    (iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run ("Tw,avg" in Equation W-32B of this subpart).
    (v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report:
    (A) Annual CO2 emissions, in metric tons CO2, from above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
    (B) Annual CH4 emissions, in metric tons CH4, from above grade metering regulating stations that are not above grade transmission-distribution transfer stations.
    (3) Onshore petroleum and natural gas production facilities must also report the information specified in paragraphs (r)(3)(i) and (ii) of this section.
    (i) Calculation method used.
    (ii) Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(3)(ii)(A) and (B) of this section, for each major equipment type, production type (i.e., natural gas or crude oil), and geographic location combination in Tables W-1B and W-1C of this subpart.
    (A) An indication of whether the facility contains the major equipment type.
    (B) If the facility does contain the equipment type, the count of the major equipment type.
    (s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (3) of this section for each emission source type listed in the most recent BOEMRE study.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (3) Annual N2O emissions, in metric tons N2O.
    (t) [Reserved]
    (u) [Reserved]
    (v) [Reserved]
    (w) EOR injection pumps. You must indicate whether CO2 EOR injection was used at your facility during the calendar year and if any EOR injection pump blowdowns occurred during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (8) of this section for each EOR injection pump system.
    (1) Sub-basin ID.
    (2) EOR injection pump system identifier.
    (3) Pump capacity, in barrels per day.
    (4) Total volume of EOR injection pump system equipment chambers, in cubic feet ("Vv" in Equation W-37 of this subpart).
    (5) Number of blowdowns for the EOR injection pump system in the calendar year.
    (6) Density of critical phase EOR injection gas, in kilograms per cubic foot ("Rc" in Equation W-37 of this subpart).
    (7) Mass fraction of CO2 in critical phase EOR injection gas ("GHGCO2" in Equation W-37 of this subpart).
    (8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system blowdowns.
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (4) of this section for each sub-basin category with EOR operations.
    (1) Sub-basin ID.
    (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels ("Vhl" in Equation W-38 of this subpart).
    (3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel under standard conditions ("Shl" in Equation W-38 of this subpart).
    (4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank ("MassCO2" in Equation W-38 of this subpart).
    (y) [Reserved]
    (z) Combustion equipment at onshore petroleum and natural gas production facilities and natural gas distribution facilities. If your facility is required by §98.232(c)(22) or (i)(7) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your facility contains any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable.
    (1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) and (ii) of this section for each unit type.
    (i) The type of combustion unit.
    (ii) The total number of combustion units.
    (2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your facility contains: External fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, then you must report the information specified in paragraphs (z)(2)(i) through (vi) of this section for each combustion unit type and fuel type combination.
    (i) The type of combustion unit.
    (ii) The type of fuel combusted.
    (iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons.
    (iv) Annual CO2 emissions, in metric tons CO2, calculated according to §98.233(z)(1) and (2).
    (v) Annual CH4 emissions, in metric tons CH4, calculated according to §98.233(z)(1) and (2).
    (vi) Annual N2O emissions, in metric tons N2O, calculated according to §98.233(z)(1) and (2).
    (aa) Each facility must report the information specified in paragraphs (aa)(1) through (9) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value.
    (1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (ii) of this section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole.
    (A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.
    (B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet.
    (C) The quantity of crude oil and condensate produced in the calendar year for sales, in barrels.
    (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category.
    (A) State.
    (B) County.
    (C) Formation type.
    (D) The number of producing wells at the end of the calendar year (exclude only those wells permanently taken out of production, i.e., plugged and abandoned) .
    (E) The number of producing wells acquired during the calendar year.
    (F) The number of producing wells divested during the calendar year.
    (G) The number of wells completed during the calendar year.
    (H) The number of wells permanently taken out of production (i.e., plugged and abandoned) during the calendar year.
    (I) Average mole fraction of CH4 in produced gas.
    (J) Average mole fraction of CO2 in produced gas.
    (K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel.
    (L) If an oil sub-basin, report the average API gravity of all wells.
    (M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge.
    (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (ii) of this section.
    (i) The total quantity of gas handled at the offshore platform in the calendar year, in thousand standard cubic feet, including production volumes and volumes transferred via pipeline from another location.
    (ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year, in barrels, including production volumes and volumes transferred via pipeline from another location.
    (3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) through (vii) of this section.
    (i) The quantity of natural gas received at the gas processing plant in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet.
    (iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.
    (iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels.
    (v) Average mole fraction of CH4 in natural gas received.
    (vi) Average mole fraction of CO2 in natural gas received.
    (vii) Indicate whether the facility fractionates NGLs.
    (4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section.
    (i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet.
    (ii) Number of compressors.
    (iii) Total compressor power rating of all compressors combined, in horsepower.
    (iv) Average upstream pipeline pressure, in pounds per square inch gauge.
    (v) Average downstream pipeline pressure, in pounds per square inch gauge.
    (5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section.
    (i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand standard cubic feet.
    (7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet.
    (8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section.
    (i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (vii) of this section.
    (i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
    (v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
    (vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet.
    (vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet.
    (bb) For any missing data procedures used, report the information in §98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of this section.
    (1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.
    (2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element.
    (cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in §98.3(b) introductory text.
Subpart X  -  Petrochemical Production
(§98.246)
All In
    In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit.
    (a) If you use the mass balance methodology in §98.243(c), you must report the information specified in paragraphs (a)(1) through (13) of this section for each type of petrochemical produced, reported by process unit.
    (1) The petrochemical process unit ID number or other appropriate descriptor.
    (2) The type of petrochemical produced, names of products, and names of carbon-containing feedstocks.
    (3) Annual CO2 emissions calculated using Equation X-4 of this subpart.
    (4) The temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X-1 of §98.243 were determined.
    (5) Annual quantity of each type of petrochemical produced from each process unit (metric tons).
    (6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.
    (i) Name of each method used to determine carbon content or molecular weight in accordance with §98.244(b)(4);
    (ii) Description of each type of device (e.g., flow meter, weighing device) used to determine flow or mass in accordance with §98.244(b)(1) through (3).
    (iii) Identification of each method (i.e., method number, title, or other description) used to determine flow or mass in accordance with §98.244(b)(1) through (3).
    (7) [Reserved]
    (8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit.
    (9) The number of days during which off-specification product was produced if the alternative to sampling and analysis specified in §98.243(c)(4) is used for a product, and, if applicable, the date of any process change that reduced the monthly average composition to less than 99.5 percent for each product or feedstock for which you comply with the alternative to sampling and analysis specified in §98.243(c)(4).
    (10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation.
    (11) If you determine carbon content or composition of a feedstock or product using a method under §98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports.
    (i) Name or title of the analytical method.
    (ii) A copy of the method. If the method is a modification of a method listed in §§98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the listed method.
    (iii) An explanation of why an alternative to the methods listed in §§98.244(b)(4)(i) through (xiv) is needed.
    (12) Name and annual quantity (in metric tons) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of §98.243.
    (13) Name and annual quantity (in metric tons) of each product included in Equations X-1, X-2, and X-3.
    (b) If you measure emissions in accordance with §98.243(b), then you must report the information listed in paragraphs (b)(1) through (10) of this section.
    (1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.
    (2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under §98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Sections 98.36(c)(2)(ii) and (c)(2)(ix) do not apply for the purposes of this subpart.
    (3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under §98.36(b)(6), (b)(7), and (e)(2)(vi).
    (4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO2 emissions that results from CO2 directly emitted by the petrochemical process unit plus CO2 generated by the combustion of off-gas from the petrochemical process unit.
    (5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH4and N2O emissions expressed in metric tons of each gas. For each CEMS monitoring location, provide an estimate based on engineering judgment of the fraction of the total CH4 and N2O emissions that is attributable to combustion of off-gas from the petrochemical process unit.
    (6) [Reserved]
    (7) Information listed in §98.256(e) of subpart Y of this part for each flare that burns process off-gas.
    (8) Annual quantity of each type of petrochemical produced from each process unit (metric tons).
    (9) Name and annual quantity (in metric tons) of each carbon-containing feedstock.
    (10) Name and annual quantity (in metric tons) of each product.
    (c) If you comply with the combustion methodology specified in §98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(5) of this section.
    (1) The ethylene process unit ID or other appropriate descriptor.
    (2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in §98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit.
    (3) Information listed in §98.256(e) of subpart Y of this part for each flare that burns ethylene process off-gas.
    (4) Name and annual quantity of each feedstock (metric tons).
    (5) Annual quantity of ethylene produced from each process unit (metric tons).
Subpart Y  -  Petroleum Refineries
(§98.256)
All In
    In addition to the reporting requirements of §98.3(c), you must report the information specified in paragraphs (a) through (q) of this section.
    (a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources).
    (b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production).
    (c)-(d) [Reserved]
    (e) For flares, owners and operators shall report:
    (1) The flare ID number (if applicable).
    (2) A description of the type of flare (steam assisted, air-assisted).
    (3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare).
    (4) The calculated CO2, CH4, and N2O annual emissions for each flare, expressed in metric tons of each pollutant emitted.
    (5) A description of the method used to calculate the CO2 emissions for each flare (e.g., reference section and equation number).
    (6) If you use Equation Y-1a of §98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), and annual average carbon content of the flare gas (in kg carbon per kg flare gas).
    (7) If you use Equation Y-1b of §98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO2 concentration (volume or mole percent), the number of carbon containing compounds other than CO2 in the flare gas stream, and for each of the carbon containing compounds other than CO2 in the flare gas stream:
    (i) The annual average concentration of the compound (volume or mole percent).
    (ii) [Reserved]
    (8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in million (MM) scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted and the annual average higher heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia.
    (9) If you use Equation Y-3 of §98.253, the number of SSM events exceeding 500,000 scf/day.
    (10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of §98.253.
    (f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in metric tons of each pollutant emitted.
    (5) A description of the method used to calculate the CO2 emissions for each unit (e.g., reference section and equation number).
    (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS (unadjusted to remove CO2 combustion emissions associated with additional units, if present) and the process CO2 emissions as calculated according to §98.253(c)(1)(ii). Report the CO2annual emissions associated with sources other than those from the coke burn-off in accordance with the applicable subpart (e.g., subpart C of this part in the case of a CO boiler).
    (7) If you use Equation Y-6 of §98.253, the annual average exhaust gas flow rate, %CO2, and %CO.
    (8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O2, %Ooxy, %CO2, and %CO.
    (9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %N2,oxy, and %N2,exhaust.
    (10) If you use Equation Y-8 of §98.253, the basis for the value of the average carbon content of coke.
    (11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH4 emissions. If you use a unit-specific emission factor for CH4, report the basis for the factor.
    (12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, report the basis for the factor.
    (13) If you use Equation Y-11 of §98.253, the number of regeneration cycles or measurement periods during the reporting year and the average coke burn-off quantity per cycle or measurement period.
    (g) For fluid coking unit of the flexicoking type, the owner or operator shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit.
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or §98.253(c).
    (5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO2, CH4, and N2O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equation input parameters specified in paragraphs (f)(7) through (f)(13) of this section.
    (h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:
    (1) The plant ID number (if applicable).
    (2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS, Equation Y-12, or process vent method in §98.253(j)).
    (3) The calculated CO2 annual emissions for each on-site sulfur recovery plant, expressed in metric tons. The calculated annual CO2 emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.
    (4) [Reserved]
    (5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under §98.253(f)(2) and (3). Indicate whether a correction for CO2 emissions in the tail gas was used in Equation Y-12 of §98.253. If so, then report:
    (i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit-specific correction was used, report the value of the correction and the approach used.
    (ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.
    (A) The annual volume of recycled tail gas (in scf/year) only.
    (B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas).
    (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual process CO2 emissions calculated according to §98.253(f)(1). Report the CO2 annual emissions associated with fuel combustion in accordance with subpart C of this part (General Stationary Fuel Combustion Sources).
    (7) If you use the process vent method in §98.253(j) for a non-Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section.
    (i) For coke calcining units, the owner and operator shall report:
    (1) The unit ID number (if applicable).
    (2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.
    (3) The calculated CO2, CH4, and N2O annual emissions for each unit, expressed in metric tons of each pollutant emitted.
    (4) A description of the method used to calculate the CO2 emissions for each unit (e.g., reference section and equation number).
    (5) If you use Equation Y-13 of §98.253, an indication of whether coke dust is recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled).
    (6) If you use a CEMS, the relevant information required under §98.36 for the Tier 4 Calculation Methodology, the CO2 annual emissions as measured by the CEMS and the annual process CO2 emissions calculated according to §98.253(g)(1).
    (7) Indicate whether you use a measured value, a unit-specific emission factor or a default emission factor for CH4emissions. If you use a unit-specific emission factor for CH4, report the basis for the factor.
    (8) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N2O emissions. If you use a unit-specific emission factor for N2O, report the basis for the factor.
    (j) For asphalt blowing operations, the owner or operator shall report:
    (1) The unit ID number (if applicable).
    (2) [Reserved]
    (3) The type of control device used to reduce methane (and other organic) emissions from the unit.
    (4) The calculated annual CO2 and CH4 emissions for each unit, expressed in metric tons of each pollutant emitted.
    (5) If you use Equation Y-14 of §98.253, the basis for the CO2 emission factor used.
    (6) If you use Equation Y-15 of §98.253, the basis for the CH4 emission factor used.
    (7) If you use Equation Y-16a of §98.253, the basis for the carbon emission factor used.
    (8) If you use Equation Y-16b of §98.253, the basis for the CO2 emission factor used and the basis for the carbon emission factor used.
    (9) If you use Equation Y-17 of §98.253, the basis for the CH4 emission factor used.
    (10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section.
    (k) For delayed coking units, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons of CH4) for all delayed coking units at the facility.
    (2) A description of the method used to calculate the CH4 emissions for each unit (e.g., reference section and equation number).
    (3) The total number of delayed coking units at the facility; the total number of delayed coking drums at the facility; and, for each coke drum or vessel, the typical drum outage (i.e. the unfilled distance from the top of the drum, in feet).
    (4) For each set of coking drums that are the same dimensions, the number of coking drums in the set, and the mole fraction of methane in coking gas (in kg-mole CH4/kg-mole gas, wet basis).
    (5) The basis for the volumetric void fraction of the coke vessel prior to steaming and the basis for the mole fraction of methane in the coking gas.
    (6) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section for each set of coke drums or vessels of the same size.
    (l) For each process vent subject to §98.253(j), the owner or operator shall report:
    (1) The vent ID number (if applicable).
    (2) The unit or operation associated with the emissions.
    (3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.
    (4) The calculated annual CO2, CH4, and N2O emissions for each vent, expressed in metric tons of each pollutant emitted.
    (5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indication of the measurement or estimation method, and for intermittent vents, the number of venting events and the cumulative venting time.
    (m) For uncontrolled blowdown systems, the owner or operator shall report:
    (1) An indication of whether the uncontrolled blowdown emission are reported under §98.253(k) or §98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems.
    (2) The cumulative annual CH4 emissions (in metric tons of CH4) for uncontrolled blowdown systems.
    (3) For uncontrolled blowdown systems reporting under §98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown systems.
    (4) For uncontrolled blowdown systems reporting under §98.253(j), the relevant information required under paragraph (l)(5) of this section.
    (n) For equipment leaks, the owner or operator shall report:
    (1) The cumulative CH4 emissions (in metric tons of each pollutant emitted) for all equipment leak sources.
    (2) The method used to calculate the reported equipment leak emissions.
    (3) The number of each type of emission source listed in Equation Y-21 of this subpart at the facility.
    (o) For storage tanks, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons of CH4) for all storage tanks, except for those used to process unstabilized crude oil.
    (2) For storage tanks other than those processing unstabilized crude oil:
    (i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude (i.e., either AP 42, Section 7.1 (incorporated by reference, see §98.7), or Equation Y-22 of this section).
    (ii) [Reserved]
    (3) The cumulative CH4 emissions (in metric tons of CH4) for storage tanks used to process unstabilized crude oil or a statement that the facility did not receive any unstabilized crude oil during the reporting year.
    (4) For storage tanks that process unstabilized crude oil:
    (i) The method used to calculate the reported unstabilized crude oil storage tank emissions.
    (ii)-(iv) [Reserved]
    (v) The basis for the mole fraction of CH4 in vent gas from unstabilized crude oil storage tanks.
    (vi) If you did not use Equation Y-23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH4 emissions for storage tanks used to process unstabilized crude oil.
    (5)-(7) [Reserved]
    (p) For loading operations, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons of each pollutant emitted) for loading operations.
    (2) The types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, etc.) in which each type of material is loaded.
    (3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).
    (q) Name of each method listed in §98.254 or a description of manufacturer's recommended method used to determine a measured parameter.
Subpart Z  -  Phosphoric Acid Production
(§98.266)
All In
    In addition to the information required by §98.3(c), each annual report must contain the information specified in paragraphs (a) through (f) of this section.
    (a) Annual phosphoric acid production, by origin of the phosphate rock (tons).
    (b) Annual phosphoric acid production capacity (tons).
    (c) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate rock from monthly records (percent by weight, expressed as a decimal fraction).
    (d) Annual phosphate rock consumption from monthly measurement records by origin (tons).
    (e) If you use a CEMS to measure CO2 emissions, then you must report the information in paragraphs (e)(1) and (e)(2) of this section.
    (1) The identification number of each wet-process phosphoric acid process line.
    (2) The annual CO2 emissions from each wet-process phosphoric acid process line (metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation Methodology.
    (f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (9) of this section.
    (1) Identification number of each wet-process phosphoric acid process line.
    (2) Annual CO2 emissions from each wet-process phosphoric acid process line (metric tons) as calculated by either Equation Z-1a or Equation Z-1b of this subpart.
    (3) Annual phosphoric acid permitted production capacity (tons) for each wet-process phosphoric acid process line (metric tons).
    (4) Method used to estimate any missing values of inorganic carbon content or carbon dioxide content of phosphate rock for each wet-process phosphoric acid process line.
    (5) [Reserved]
    (6) [Reserved]
    (7) Number of wet-process phosphoric acid process lines.
    (8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO2 contents of the phosphate rock (months).
    (9) Annual process CO2 emissions from phosphoric acid production facility (metric tons).
Subpart AA  -  Pulp and Paper Manufacturing
(§98.276)
25,000 metric tons C02e/year
    In addition to the information required by §98.3(c) and the applicable information required by §98.36, each annual report must contain the information in paragraphs (a) through (l) of this section as applicable:
    (a) Annual emissions of CO2, biogenic CO2, CH4, biogenic CH4 N2O, and biogenic N2O (metric tons per year).
    (b) [Reserved]
    (c) Basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see §98.7) or an online measurement system).
    (d) [Reserved]
    (e) The default emission factor for CO2, CH4, or N2O, used in Equation AA-1 of this subpart (kg CO2, CH4, or N2O per mmBtu).
    (f)-(i) [Reserved]
    (j) Annual steam purchases (pounds of steam per year).
    (k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total.
    (l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and (2) of this section.
    (1) The quantity of calcium oxide (CaO) produced (metric tons).
    (2) The percent of annual heat input, individually for each fossil fuel type.

Subpart BB  -  Silicon Carbide Production
(§98.286)
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 for each silicon carbide production facility.
    (a) If a CEMS is used to measure process CO2 emissions, you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in §98.36 and the information listed in this paragraph (a):
    (1) Annual consumption of petroleum coke (tons).
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (b) If a CEMS is not used to measure process CO2 emissions, you must report the information in paragraph (b)(1) through (8) of this section for all silicon carbide process units or production furnaces combined:
    (1) [Reserved]
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (4) [Reserved]
    (5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method.
    (6) [Reserved]
    (7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under §98.284(d) (percent by weight expressed as a decimal fraction).
    (8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).

Subpart CC  -  Soda Ash Manufacturing
(§98.296)

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 appropriate for each soda ash manufacturing facility.
    (a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required under §98.36 and the following information in this paragraph (a):
    (1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).
    (2) Annual production of soda ash for each manufacturing line (tons).
    (3) Annual production capacity of soda ash for each manufacturing line (tons).
    (4) Identification number of each manufacturing line.
    (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in this paragraph (b):
    (1) Identification number of each manufacturing line.
    (2) Annual process CO2 emissions from each soda ash manufacturing line (metric tons).
    (3) Annual production of soda ash for each manufacturing line (tons).
    (4) Annual production capacity of soda ash for each manufacturing line (tons).
    (5)-(7) [Reserved]
    (8) Whether CO2 emissions for each manufacturing line were calculated using a trona input method as described in Equation CC-1 of this subpart, a soda ash output method as described in Equation CC-2 of this subpart, or a site-specific emission factor method as described in Equations CC-3 through CC-5 of this subpart.
    (9) Number of manufacturing lines located used to produce soda ash.
    (10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§98.293(b)(3)) to estimate emissions then you must report the following relevant information for each manufacturing line or stack:
    (i) Stack gas volumetric flow rate during performance test (dscfm).
    (ii) Hourly CO2 concentration during performance test (percent CO2).
    (iii) CO2 emission factor (metric tons CO2/metric tons of process vent flow from mine water stripper/evaporator).
    (iv) CO2 mass emission rate during performance test (metric tons/hour).
    (v) Average process vent flow from mine water stripper/evaporator during performance test (pounds/hour).
    (vi) Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour).
    (11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11):
    (i) Trona or soda ash (number of months).
    (ii) Inorganic carbon contents of trona or soda ash (weeks).
    (iii) Process vent flow rate from mine water stripper/evaporator (number of months).

Subpart DD- Electrical Transmission and Distribution Equipment Use
(§98.306)
Electrical transmission and distribution equipment use at facilities where the total nameplate capacity of SF6and PFC containing equipment exceeds 17,820 pounds
    In addition to the information required by §98.3(c), each annual report must contain the following information for each electric power system, by chemical:
    (a) Nameplate capacity of equipment (pounds) containing SF6 and nameplate capacity of equipment (pounds) containing each PFC:
    (1) Existing at the beginning of the year (excluding hermetically sealed-pressure switchgear).
    (2) New during the year (all SF6-insulated equipment, including hermetically sealed-pressure switchgear).
    (3) Retired during the year (all SF6-insulated equipment, including hermetically sealed-pressure switchgear).
    (b) Transmission miles (length of lines carrying voltages above 35 kilovolt).
    (c) Distribution miles (length of lines carrying voltages at or below 35 kilovolt).
    (d) Pounds of SF6 and PFC stored in containers, but not in energized equipment, at the beginning of the year.
    (e) Pounds of SF6 and PFC stored in containers, but not in energized equipment, at the end of the year.
    (f) Pounds of SF6 and PFC purchased in bulk from chemical producers or distributors.
    (g) Pounds of SF6 and PFC purchased from equipment manufacturers or distributors with or inside equipment, including hermetically sealed-pressure switchgear.
    (h) Pounds of SF6 and PFC returned to facility after off-site recycling.
    (i) Pounds of SF6 and PFC in bulk and contained in equipment sold to other entities.
    (j) Pounds of SF6 and PFC returned to suppliers.
    (k) Pounds of SF6 and PFC sent off-site for recycling.
    (l) Pounds of SF6 and PFC sent off-site for destruction.

Subpart EE  -  Titanium Dioxide Production
(§98.316)
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 for each titanium dioxide production line.
    (a) If a CEMS is used to measure CO2 emissions, then you must report the relevant information required under §98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a).
    (1) Identification number of each process line.
    (2) Annual consumption of calcined petroleum coke (tons).
    (3) Annual production of titanium dioxide (tons).
    (4) Annual production capacity of titanium dioxide (tons).
    (5) Annual production of carbon-containing waste (tons), if applicable.
    (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in this paragraph (b):
    (1) Identification number of each process line.
    (2) Annual CO2 emissions from each chloride process line (metric tons/year).
    (3) Annual consumption of calcined petroleum coke for each process line (tons).
    (4) Annual production of titanium dioxide for each process line (tons).
    (5) Annual production capacity of titanium dioxide for each process line (tons).
    (6) [Reserved]
    (7) Annual production of carbon-containing waste for each process line (tons), if applicable.
    (8) Monthly production of titanium dioxide for each process line (tons).
    (9) [Reserved]
    (10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard methods.
    (11) Carbon content for carbon-containing waste for each process line (percent by weight expressed as a decimal fraction).
    (12) If carbon content of petroleum coke is based on self measurement, the ASTM standard methods used.
    (13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under §98.314(d) (percent by weight expressed as a decimal fraction).
    (14) Number of separate chloride process lines located at the facility.
    (15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year).
Subpart FF  -  Underground Coal Mines
(§98.326)
Underground coal mines liberating 36,500,000 actual cubic feet of CH4 or more per year
    In addition to the information required by §98.3(c), each annual report must contain the following information for each mine:
    (a) Quarterly CH4 liberated from each ventilation monitoring point, (metric tons CH4).
    (b) Weekly CH4 liberated from each degasification system monitoring point (metric tons CH4).
    (c) Quarterly CH4 destruction at each ventilation and degasification system destruction device or point of offsite transport (metric tons CH4).
    (d) Quarterly CH4 emissions (net) from all ventilation and degasification systems (metric tons CH4).
    (e) Quarterly CO2 emissions from on-site destruction of coal mine gas CH4, where the gas is not a fuel input for energy generation or use (e.g., flaring) (metric tons CO2).
    (f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF-1 of this subpart.
    (g) Quarterly CH4 concentration for each ventilation monitoring point, dates and locations of each measurement and method of measurement (sampling or continuous monitoring).
    (h) Weekly volumetric flow rate used to calculate CH4 liberated from degasification systems and units of measure (acfm or scfm), and method of measurement (sampling or continuous monitoring), used in Equation FF-3 of this subpart.
    (i) Quarterly CH4 concentration (%) used to calculate CH4 liberated from degasification systems and if the data is based on CEMS or weekly sampling.
    (j) Weekly volumetric flow rate used to calculate CH4 destruction for each destruction device and each point of offsite transport, and units of measure (acfm or scfm).
    (k) Weekly CH4 concentration (%) used to calculate CH4 flow to each destruction device and each point of offsite transport (C).
    (l) Dates in quarterly reporting period where active ventilation of mining operations is taking place.
    (m) Dates in quarterly reporting period where degasification of mining operations is taking place.
    (n) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.
    (o) Temperatures (°R), pressure (atm), moisture content, and the moisture correction factor (if applicable) used in Equation FF-1 and FF-3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF-9 was required.
    (p) For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site. If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent).
    (q) A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters), and the annual operating hours of the gas collection system.
    (r) Identification information and description for each well, shaft, and vent hole, including paragraphs (r)(1) through (r)(3) of this section:
    (1) Indication of whether the well, shaft, or vent hole is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
    (2) Start date and close date of each well, shaft, and vent hole.
    (3) Number of days the well, shaft, or vent hole was in operation during the reporting year.
    (s) For each centralized monitoring point, identification of the wells and shafts included in the point. Note which method (sampling or continuous monitoring) was used.
    (t) Mine Safety and Health Administration (MSHA) identification for this coal mine.
Subpart GG  -  Zinc Production
(§98.336)
25,000 metric tons C02e/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, for each Waelz kiln or electrothermic furnace.
    (a) If a CEMS is used to measure CO2 emissions, then you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in §98.36 and the information listed in this paragraph (a):
    (1) Annual zinc product production capacity (tons).
    (2) Annual production quantity for each zinc product (tons).
    (3) Annual facility production quantity for each zinc product (tons).
    (4) Number of Waelz kilns at each facility used for zinc production.
    (5) Number of electrothermic furnaces at each facility used for zinc production.
    (b) If a CEMS is not used to measure CO2 emissions, then you must report the information listed in this paragraph (b):
    (1) Identification number and annual process CO2 emissions from each individual Waelz kiln or electrothermic furnace (metric tons).
    (2) Annual zinc product production capacity (tons).
    (3) Annual production quantity for each zinc product (tons).
    (4) Number of Waelz kilns at each facility used for zinc production.
    (5) Number of electrothermic furnaces at each facility used for zinc production.
    (6) [Reserved]
    (7) [Reserved]
    (8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.
    (9) If carbon content of each carbon-containing input material charged to each kiln or furnace is based on self measurement, the ASTM Standard Test Method used.
    (10) [Reserved]
    (11) Whether carbon content of the carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.
    (12) If carbon content of carbon electrode used in each furnace is based on self measurement, the ASTM standard method used.
    (13) If you use the missing data procedures in §98.335(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
Subpart HH  -  Municipal Solid Waste Landfills
(§98.346)
Municipal solid waste landfills that generate CH4 in amounts equivalent to 25,000 metric tons CO2e or more per year
    In addition to the information required by §98.3(c), each annual report must contain the following information for each landfill.
    (a) A classification of the landfill as "open" (actively received waste in the reporting year) or "closed" (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used), an indication as to whether scales are present at the landfill, and the waste disposal quantity for each year of landfilling required to be included when using Equation HH-1 of this subpart (in metric tons, wet weight).
    (b) Method for estimating reporting year and historical waste disposal quantities, reason for its selection, and the range of years it is applied. For years when waste quantity data are determined using the methods in §98.343(a)(3), report separately the quantity of waste determined using the methods in §98.343(a)(3)(i) and the quantity of waste determined using the methods in §98.343(a)(3)(ii). For historical waste disposal quantities that were not determined using the methods in §98.343(a)(3), provide the population served by the landfill for each year the Equation HH-2 of this subpart is applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide the value of landfill capacity (LFC) used in the calculation.
    (c) Waste composition for each year required for Equation HH-1 of this subpart, in percentage by weight, for each waste category listed in Table HH-1 to this subpart that is used in Equation HH-1 of this subpart to calculate the annual modeled CH4 generation.
    (d) For each waste type used to calculate CH4 generation using Equation HH-1 of this subpart, you must report:
    (1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOCF) values used in the calculations.
    (2) Decay rate (k) value used in the calculations.
    (e) Fraction of CH4 in landfill gas (F), an indication of whether the fraction of CH4 was determined based on measured values or the default value, and the methane correction factor (MCF) used in the calculations. If an MCF other than the default of 1 is used, provide an indication of whether active aeration of the waste in the landfill was conducted during the reporting year, a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
    (f) The surface area of the landfill containing waste (in square meters), identification of the type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures). If multiple cover types are used, the surface area associated with each cover type.
    (g) The modeled annual methane generation rate for the reporting year (metric tons CH4) calculated using Equation HH-1 of this subpart.
    (h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH4, the oxidation fraction used in the calculation, and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at this landfill.
    (i) For landfills with gas collection systems, you must report:
    (1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520 °R or 60 degrees Fahrenheit and 1 atm).
    (2) Annual average CH4 concentration of landfill gas collected for destruction (percent by volume).
    (3) Monthly average temperature and pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature and/or pressure is incorporated into internal calculations run by the monitoring equipment.
    (4) An indication as to whether flow was measured on a wet or dry basis, an indication as to whether CH4concentration was measured on a wet or dry basis, and if required for Equation HH-4 of this subpart, monthly average moisture content for each month at which flow is measured for landfill gas collected for destruction.
    (5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location the number of destruction devices associated with that measurement location and the annual operating hours and the destruction efficiency (percent) for each destruction device associated with that measurement location.
    (6) Annual quantity of recovered CH4 (metric tons CH4) calculated using Equation HH-4 of this subpart for each measurement location.
    (7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH-3 to this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, the annual operating hours of the gas collection system for each measurement location, and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in §98.6) are present at the landfill.
    (8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation.
    (9) Methane generation (GCH4) value used as an input to Equation HH-6 of this subpart. Specify whether the value is modeled (GCH4 from HH-1 of this subpart) or measured (R from Equation HH-4 of this subpart).
    (10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation.
    (11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation.
    (12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH4, and the oxidation fraction used in the calculation.
Subpart II  -  Industrial Wastewater Management
(§98.356)
25,000 metric tons C02e/year
    In addition to the information required by §98.3(c), each annual report must contain the following information for each wastewater treatment system.
    (a) A description or diagram of the industrial wastewater treatment system, identifying the processes used to treat industrial wastewater and industrial wastewater treatment sludge. Indicate how the processes are related to each other and identify the anaerobic processes. Provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered. The anaerobic processes must be identified as:
    (1) Anaerobic reactor.
    (2) Anaerobic deep lagoon (depth more than 2 meters).
    (3) Anaerobic shallow lagoon (depth less than 2 meters).
    (4) Anaerobic sludge digester.
    (b) For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon) you must report:
    (1) Weekly average COD or BOD5 concentration of wastewater entering each anaerobic wastewater treatment process, for each week the anaerobic process was operated.
    (2) Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated.
    (3) Maximum CH4 production potential (B0) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart.
    (4) Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart.
    (5) Annual mass of CH4 generated by each anaerobic wastewater treatment process, calculated using Equation II-1 or II-2 of this subpart.
    (c) For each anaerobic wastewater treatment process from which biogas is not recovered, you must report the annual CH4 emissions, calculated using Equation II-3 of this subpart.
    (d) For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report:
    (1) Annual quantity of CH4 recovered from the anaerobic process calculated using Equation II-4 of this subpart.
    (2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction.
    (3) Weekly average CH4 concentration for each week that biogas is collected for destruction.
    (4) Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calculations.
    (5) Whether flow was measured on a wet or dry basis, whether CH4 concentration was measured on a wet or dry basis, and if required for Equation II-4 of this subpart, weekly average moisture content for each week at which flow is measured for biogas collected for destruction, or statement that moisture content is incorporated into monitoring equipment internal calculations.
    (6) Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calculations.
    (7) CH4 collection efficiency (CE) used in Equation II-5 of this subpart.
    (8) Whether destruction occurs at the facility or off-site. If destruction occurs at the facility, also report whether a back-up destruction device is present at the facility, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), the destruction efficiency for the primary destruction device, and the destruction efficiency for the back-up destruction device (if present).
    (9) For each anaerobic process from which some biogas is recovered, you must report the annual CH4 emissions, as calculated by Equation II-6 of this subpart.
    (e) The total mass of CH4 emitted from all anaerobic processes from which biogas is not recovered (calculated in Equation II-3 of this subpart) and from all anaerobic processes from which some biogas is recovered (calculated in Equation II-6 of this subpart) using Equation II-7 of this subpart.

Subpart JJ  -  Manure Management
(§98.366)
Manure management systems with combined CH4 and N2O emissions in amounts equivalent to 25,000 metric tons CO2e or more per year
    (a) In addition to the information required by §98.3(c), each annual report must contain the following information:
    (1) List of manure management system components at the facility.
    (2) Fraction of manure from each animal type that is handled in each manure management system component.
    (3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ-4 for growing populations.
    (4) Average number of days that growing animals are kept at the facility (for each animal type).
    (5) The number of animals produced annually for growing populations (for each animal type).
    (6) Typical animal mass (for each animal type).
    (7) Total facility emissions (results of Equation JJ-15).
    (8) CH4 emissions from manure management system components listed in §98.360(b), except digesters (results of Equation JJ-2).
    (9) VS value used (for each animal type).
    (10) B0 value used (for each animal type).
    (11) Methane conversion factor used for each MMS component.
    (12) Average ambient temperature used to select each methane conversion factor.
    (13) N2O emissions (results of Equation JJ-13).
    (14) N value used for each animal type.
    (15) N2O emission factor selected for each MMS component.
    (b) Facilities with anaerobic digesters must also report:
    (1) CH4 emissions from anaerobic digesters (results of Equation JJ-5).
    (2) CH4 flow to the digester combustion device for each digester (results of Equation JJ-6, or value from fully integrated monitoring system as described in 98.363(b)).
    (3) CH4 destruction for each digester (results of Equation JJ-11).
    (4) CH4 leakage for each digester (results of Equation JJ-12).
    (5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).
    (6) Average annual CH4 concentration for each digester (results of Equation JJ-8).
    (7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ-9).
    (8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ-10).
    (9) Destruction efficiency used for each digester.
    (10) Number of days per year that each digester was operating.
    (11) Collection efficiency used for each digester.

Subpart LL  -  Suppliers of Coal-Based Liquid Fuels
(§98.386)
Producers of coal-to-liquid products:  All in

Importers & Exporters: 25,000 metric tons C02e/year
    In addition to the information required by §98.3(c), the following requirements apply:
    (a) Producers shall report the following information for each coal-to-liquid facility:
    (1) [Reserved]
    (2) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(2) of this section.
    (5) [Reserved]
    (6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(2), shall not be reported under this paragraph.
    (7) For each product reported in paragraph (a)(6) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
    (8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(6) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or metric ton of product.
    (12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Method 2 of subpart MM of this part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) [Reserved]
    (14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(14) of this section.
    (16) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated according to §98.393(b) or (h).
    (17) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in paragraph (a)(6) of this section that were calculated according to §98.393(a) or (h).
    (18) Annual CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c).
    (19) Annual CO2 emissions that would result from the complete combustion or oxidation of all products, calculated according to §98.393(d).
    (20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.
    (b) In addition to the information required by §98.3(c), each importer shall report all of the following information at the corporate level:
    (1) [Reserved]
    (2) For each product listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of subpart MM of this part.
    (3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(2) of this section.
    (5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each imported product reported in paragraph (b)(2) of this section, calculated according to §98.393(a).
    (8) The total sum of CO2 emissions that would result from the complete combustion or oxidation of all imported products, calculated according to §98.393(e).
    (c) In addition to the information required by §98.3(c), each exporter shall report all of the following information at the corporate level:
    (1) [Reserved]
    (2) For each product listed in table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
    (3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
    (4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(2) of this section.
    (5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each exported product reported in paragraph (c)(2) of this section, calculated according to §98.393(a).
    (8) Total sum of CO2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to §98.393(e).
    (d) Blended feedstock and products. (1) Producers, exporters, and importers must report the following information for each blended product and feedstock where emissions were calculated according to §98.393(i):
    (i) Volume or mass of each blending component.
    (ii) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each blended feedstock or product, using Equation MM-12 or Equation MM-13 of §98.393.
    (iii) Whether it is a blended feedstock or a blended product.
    (2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock.
    (3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.

Subpart MM  -  Suppliers of Petroleum Products
(§98.396)
(A) All petroleum refineries that distill crude oil.
(B) Importers of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO2e or more.
(C) Exporters of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO2e or more.
    In addition to the information required by §98.3(c), the following requirements apply:
    (a) Refiners shall report the following information for each facility:
    (1) [Reserved]
    (2) For each petroleum product or natural gas liquid listed in Table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
    (4)-(5) [Reserved]
    (6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this paragraph.
    (7) For each product reported in paragraph (a)(6) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
    (8) [Reserved]
    (9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) [Reserved]
    (14) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.
    (15) [Reserved]
    (16) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section that were calculated according to §98.393(a) or (h).
    (17) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated according to §98.393(b) or (h).
    (18) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph (a)(14) of this section, calculated according to §98.393(c).
    (19) The sum of CO2 emissions that would result from the complete combustion or oxidation of all products, calculated according to §98.393(d).
    (20) For all crude oil that enters the refinery, report the annual quantity in barrels.
    (21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section.
    (22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.
    (b) In addition to the information required by §98.3(c), each importer shall report all of the following information at the corporate level:
    (1) [Reserved]
    (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
    (3) For each product reported in paragraph (b)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
    (4) [Reserved]
    (5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to §98.393(a).
    (8) The sum of CO2 emissions that would result from the complete combustion oxidation of all imported products, calculated according to §98.393(e).
    (c) In addition to the information required by §98.3(c), each exporter shall report all of the following information at the corporate level:
    (1) [Reserved]
    (2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
    (3) For each product reported in paragraph (c)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is petroleum based (excluding any denaturant that may be present in any ethanol product).
    (4) [Reserved]
    (5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to §98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result from the complete combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to §98.393(a).
    (8) The sum of CO2 emissions that would result from the complete combustion or oxidation of all exported products, calculated according to §98.393(e).
    (d) Blended non-crude feedstock and products. (1) Refineries, exporters, and importers must report the following information for each blended product and non-crude feedstock where emissions were calculated according to §98.393(i):