40 CFR 98.236 - Data reporting requirements.

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§ 98.236 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section.
(a) Report annual emissions in metric tons of CO2e for each GHG separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this section.
(1) Onshore petroleum and natural gas production.
(2) Offshore petroleum and natural gas production.
(3) Onshore natural gas processing.
(4) Onshore natural gas transmission compression.
(5) Underground natural gas storage.
(6) LNG storage.
(7) LNG import and export.
(8) Natural gas distribution.
(b) For offshore petroleum and natural gas production, report emissions of CH4, CO2, and N2O as applicable to the source type (in metric tons CO2e per year at standard conditions) individually for all of the emissions source types listed in the most recent BOEMRE study.
(c) Report the information listed in this paragraph for each applicable source type in metric tons of CO2e for each GHG. If a facility operates under more than one industry segment, each piece of equipment should be reported under the unit's respective majority use segment. When a source type listed under this paragraph routes gas to flare, separately report the emissions that were vented directly to the atmosphere without flaring, and the emissions that resulted from flaring the gas. Both the vented and flared emissions will be reported under the respective source type and not under the flare source type.
(1) For natural gas pneumatic devices (refer to Equation W-1 of § 98.233), report the following:
(i) Actual count and estimated count separately of natural gas pneumatic high bleed devices as applicable.
(ii) Actual count and estimated count separately of natural gas pneumatic low bleed devices as applicable.
(iii) Actual count and estimated count separately of natural gas pneumatic intermittent bleed devices as applicable.
(iv) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, for each of the following pieces of equipment: high bleed pneumatic devices; intermittent bleed pneumatic devices; low bleed pneumatic devices.
(2) For natural gas driven pneumatic pumps (refer to Equation W-2 of § 98.233), report the following,
(i) Count of natural gas driven pneumatic pumps.
(ii) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, for all natural gas driven pneumatic pumps combined.
(3) For each acid gas removal unit (refer to Equation W-3 and Equation W-4 of § 98.233), report the following:
(i) Total throughput off the acid gas removal unit using a meter or engineering estimate based on process knowledge or best available data in million cubic feet per year.
(ii) For Calculation Methodology 1 and Calculation Methodology 2 of § 98.233(d), annual average fraction of CO2 content in the vent from the acid gas removal unit (refer to § 98.233(d)(6)).
(iii) For Calculation Methodology 3 of § 98.233(d), annual average volume fraction of CO2 content of natural gas into and out of the acid gas removal unit (refer to § 98.233(d)(7) and (d)(8)).
(iv) Report the annual quantity of CO2, expressed in metric tons CO2e, that was recovered from the AGR unit and transferred outside the facility, under subpart PP of this part.
(v) Report annual CO2 emissions for the AGR unit, expressed in metric tons CO2e.
(vi) For the onshore natural gas processing industry segment only, report a unique name or ID number for the AGR unit.
(vii) An indication of which calculation methodology was used for the AGR.
(4) For dehydrators, report the following:
(i) For each Glycol dehydrator with a throughput greater than or equal to 0.4 MMscfd (refer to § 98.233(e)(1)), report the following:
(A) Glycol dehydrator feed natural gas flow rate in MMscfd, determined by engineering estimate based on best available data.
(B) Glycol dehydrator absorbent circulation pump type.
(C) Whether stripper gas is used in glycol dehydrator.
(D) Whether a flash tank separator is used in glycol dehydrator.
(E) Type of absorbent.
(F) Total time the glycol dehydrator is operating in hours.
(G) Temperature, in degrees Fahrenheit and pressure, in psig, of the wet natural gas.
(H) Concentration of CH4 and CO2 in wet natural gas.
(I) What vent gas controls are used (refer to § 98.233(e)(3) and (e)(4)).
(J) For each glycol dehydrator, report annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas.
(K) For each glycol dehydrator, report annual CO2, CH4, and N2O emissions that resulted from flaring process gas from the dehydrator, expressed in metric tons CO2e for each gas.
(L) For the onshore natural gas processing industry segment only, report a unique name or ID number for glycol dehydrator.
(ii) For all glycol dehydrators with a throughput less than 0.4 MMscfd (refer to § 98.233, Equation W-5 of § 98.233), report the following:
(A) Count of glycol dehydrators.
(B) Which vent gas controls are used (refer to § 98.233(e)(3) and (e)(4)).
(C) Report annual CO2 and CH4 emissions at the facility level that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas, combined for all glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd.
(D) Report annual CO2, CH4, and N2O emissions at the facility level that resulted from the flaring of process gas, expressed in metric tons CO2e for each gas, combined for all glycol dehydrators with annual average daily throughput of less than 0.4 MMscfd.
(iii) For absorbent desiccant dehydrators (refer to Equation W-6 of § 98.233), report the following:
(A) Count of desiccant dehydrators.
(B) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, for all absorbent desiccant dehydrators combined.
(5) For well venting for liquids unloading, report the following:
(i) For Calculation Methodology 1 (refer to Equation W-7 of § 98.233), report the following for each tubing diameter group and pressure group combination within each sub-basin category:
(A) Count of wells vented to the atmosphere for liquids unloading.
(B) Count of plunger lifts. Whether the selected well from the tubing diameter and pressure group combination had a plunger lift (yes/no).
(C) Cumulative number of unloadings vented to the atmosphere.
(D) Average flow rate of the measured well venting in cubic feet per hour (refer to § 98.233(f)(1)(i)(A)).
(E) Internal casing diameter or internal tubing diameter in inches, where applicable, and well depth of each well, in feet, selected to represent emissions in that tubing size and pressure combination.
(F) Casing pressure, in psia, of each well selected to represent emissions in that tubing size group and pressure group combination that does not have a plunger lift.
(G) Tubing pressure, in psia, of each well selected to represent emissions in a tubing size group and pressure group combination that has a plunger lift.
(H) Report annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas.
(ii) For Calculation Methodologies 2 and 3 (refer to Equation W-8 and W-9 of § 98.233), report the following for each sub-basin category:
(A) Count of wells vented to the atmosphere for liquids unloading.
(B) Count of plunger lifts.
(C) Cumulative number of unloadings vented to the atmosphere.
(D) Average internal casing diameter, in inches, of each well, where applicable.
(E) Report annual CO2 and CH4 emissions, expressed in metric tons CO2e for each GHG gas.
(6) For well completions and workovers, report the following for each sub-basin category:
(i) For gas well completions and workovers with hydraulic fracturing by sub-basin and well type (horizontal or vertical) combination (refer to Equation W-10A and W-10B of § 98.233), report the following:
(A) Total count of completions in calendar year.
(B) When using Equation W-10A, measured flow rate of backflow during well completion in standard cubic feet per hour.
(C) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere.
(D) When using Equation W-10A, measured flow rate of backflow during well workover in standard cubic feet per hour.
(E) When using Equation W-10A, total number of days of backflow from all wells during completions.
(F) When using Equation W-10A, total number of days of backflow from all wells during workovers.
(G) Report number of completions employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best available.
(H) Report number of workovers employing purposely designed equipment that separates natural gas from the backflow and the amount of natural gas, in standard cubic feet, recovered using engineering estimate based on best available data.
(I) Annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas.
(J) Annual CO2, CH4, and N2O emissions that resulted from flares, expressed in metric tons CO2e for each gas.
(ii) For gas well completions and workovers without hydraulic fracturing (refer to Equation W-13 of § 98.233):
(A) Total count of completions in calendar year.
(B) Total count of workovers in calendar year that flare gas or vent gas to the atmosphere.
(C) Total number of days of gas venting to the atmosphere during backflow for completion.
(D) Annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas.
(E) Annual CO2, CH4, and N2O emissions that resulted from flares, expressed in metric tons CO2e for each gas.
(7) For blowdown vent stack emission source, (refer to Equation W-14A and Equation W-14B of § 98.233), report the following:
(i) For each unique physical volume that is blown down more than once during the calendar year, report the following:
(A) Total number of blowdowns for each unique physical volume in the calendar year.
(B) Annual CO2 and CH4 emissions, for each unique physical blowdown volume, expressed in metric tons CO2e for each gas.
(C) A unique name or ID number for the unique physical volume.
(ii) For all unique volumes that are blown down once during the calendar year, report the following:
(A) Total number of blowdowns for all unique physical volumes in the calendar year.
(B) Annual CO2 and CH4 emissions from all unique physical volumes as an aggregate per facility, expressed in metric tons CO2e for each gas.
(8) For gas emitted from produced oil sent to atmospheric tanks:
(i) For wellhead gas-liquid separator with oil throughput greater than or equal to 10 barrels per day, using Calculation Methodology 1 and 2 of § 98.233(j), report the following by sub-basin category, unless otherwise specified:
(A) Number of wellhead separators sending oil to atmospheric tanks.
(B) Estimated average separator temperature, in degrees Fahrenheit, and estimated average pressure, in psig.
(C) Estimated average sales oil stabilized API gravity, in degrees.
(D) Count of hydrocarbon tanks at well pads.
(E) Best estimate of count of stock tanks not at well pads receiving your oil.
(F) Total volume of oil from all wellhead separators sent to tank(s) in barrels per year.
(G) Count of tanks with emissions control measures, either vapor recovery system or flaring, for tanks at well pads.
(H) Best estimate of count of stock tanks assumed to have emissions control measures not at well pads, receiving your oil.
(I) Range of concentrations of flash gas, CH4 and CO2.
(J) Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO2e for each gas, for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 2 of § 98.233(j).
(K) Annual CO2 and CH4 gas quantities that were recovered, expressed in metric tons CO2e for each gas, for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 2 of § 98.233(j).
(L) Annual CO2, CH4, and N2O emissions that resulted from flaring gas, expressed in metric tons CO2e for each gas, for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 1, and for all wellhead gas-liquid separators or storage tanks using Calculation Methodology 2 of § 98.233(j).
(ii) For wells with oil production greater than or equal to 10 barrels per day, using Calculation Methodology 3 and 4 of § 98.233(j), report the following by sub-basin category:
(A) Total volume of sales oil from all wells in barrels per year.
(B) Total number of wells sending oil directly to tanks.
(C) Total number of wells sending oil to separators off the well pads.
(D) Sales oil API gravity range for wells in (c)(8)(ii)(B) and (c)(8)(ii)(C) of this section, in degrees.
(E) Count of hydrocarbon tanks on wellpads.
(F) Count of hydrocarbon tanks, both on and off well pads assumed to have emissions control measures: either vapor recovery system or flaring of tank vapors.
(G) Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 3 or 4 of § 98.233(j).
(H) Annual CO2 and CH4 gas quantities that were recovered, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 3 or 4 of § 98.233(j).
(I) Annual CO2, CH4, and N2O emissions that resulted from flaring gas, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 3 and 4 of § 98.233(j).
(iii) For wellhead gas-liquid separators and wells with throughput less than 10 barrels per day, using Calculation Methodology 5 of § 98.233(j) Equation W-15 of § 98.233, report the following:
(A) Number of wellhead separators.
(B) Number of wells without wellhead separators.
(C) Total volume of oil production in barrels per year.
(D) Best estimate of fraction of production sent to tanks with assumed control measures: either vapor recovery system or flaring of tank vapors.
(E) Count of hydrocarbon tanks on well pads.
(F) Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 5 of § 98.233(j).
(G) Annual CO2 and CH4 gas quantities that were recovered, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 5 of § 98.233(j).
(H) Annual CO2, CH4, and N2O emissions that resulted from flaring gas, expressed in metric tons CO2e for each gas, at the sub-basin level for Calculation Methodology 5 of § 98.233(j).
(iv) If wellhead separator dump valve is functioning improperly during the calendar year (refer to Equation W-16 of § 98.233), report the following:
(A) Count of wellhead separators that dump valve factor is applied.
(B) Annual CO2 and CH4 emissions that resulted from venting gas to the atmosphere, expressed in metric tons CO2e for each gas, at the sub-basin level for improperly functioning dump valves.
(9) For transmission tank emissions identified using optical gas imaging instrument per § 98.234(a) (refer to § 98.233(k)), or acoustic leak detection of scrubber dump valves, report the following:
(i) For each vent stack, report annual CO2 and CH4 emissions that resulted from venting gas directly to the atmosphere, expressed in metric tons CO2e for each gas.
(ii) For each transmission storage tank, report annual CO2, CH4, and N2O emissions that resulted from flaring process gas from the transmission storage tank, expressed in metric tons CO2e for each gas.
(iii) A unique name or ID number for the vent stack monitored according to 40 CFR 98.233(k).
(10) For well testing venting and flaring (refer to Equation W-17A or W-17B of § 98.233), report the following:
(i) Number of wells tested per basin in calendar year.
(ii) Average gas to oil ratio for each basin.
(iii) Average number of days the well is tested in a basin.
(iv) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from well testing venting.
(v) Report annual CO2, CH4, and N2O emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from well testing flaring.
(11) For associated natural gas venting and flaring (refer to Equation W-18 of § 98.233), report the following for each basin:
(i) Number of wells venting or flaring associated natural gas in a calendar year.
(ii) Average gas to oil ratio for each basin.
(iii) Report annual CO2 and CH4 emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from associated natural gas venting.
(iv) Report annual CO2, CH4, and N2O emissions at the facility level, expressed in metric tons CO2e for each gas, emissions from associated natural gas flaring.
(12) For flare stacks (refer to Equation W-19, W-20, and W-21 of § 98.233), report the following for each flare:
(i) Whether flare has a continuous flow monitor.
(ii) Volume of gas sent to flare in cubic feet per year.
(iii) Percent of gas sent to un-lit flare determined by engineering estimate and process knowledge based on best available data and operating records.
(iv) Whether flare has a continuous gas analyzer.
(v) Flare combustion efficiency.
(vi) Report uncombusted CH4 emissions, in metric tons CO2e (refer to Equation W-19 of § 98.233).
(vii) Report uncombusted CO2 emissions, in metric tons CO2e (refer to Equation W-20 of § 98.233).
(viii) Report combusted CO2 emissions, in metric tons CO2e (refer to Equation W-21 of § 98.233).
(ix) Report N2O emissions, in metric tons CO2e.
(x) For the natural gas processing industry segment, a unique name or ID number for the flare stack.
(xi) In the case that a CEMS is used to measure CO2 emissions for the flare stack, indicate that a CEMS was used in the annual report and report the combusted CO2 and uncombusted CO2 as a combined number.
(13) For each centrifugal compressor:
(i) For compressors with wet seals in operational mode (refer to Equations W-22 through W-24 of § 98.233), report the following for each degassing vent:
(A) Number of wet seals connected to the degassing vent.
(B) Fraction of vent gas recovered for fuel or sales or flared.
(C) Annual throughput in million scf, use an engineering calculation based on best available data.
(D) Type of meters used for making measurements.
(E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W-24 of § 98.233).
(F) Total time the compressor is operating in hours.
(G) Report seal oil degassing vent emissions for compressors measured (refer to Equation W-22 of § 98.233) and for compressors not measured (refer to Equation W-23 and Equation W-24 of § 98.233).
(ii) For wet and dry seal centrifugal compressors in operating mode, (refer to Equations W-22 through W-24 of § 98.233), report the following:
(A) Total time in hours the compressor is in operating mode.
(B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to Equation W-24 of § 98.233).
(C) Report blowdown vent emissions when in operating mode (refer to Equation W-23 and Equation W-24 of § 98.233).
(iii) For wet and dry seal centrifugal compressors in not operating, depressurized mode (refer to Equations W-22 through W-24 of § 98.233), report the following:
(A) Total time in hours the compressor is in shutdown, depressurized mode.
(B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per hour (refer to Equation W-24 of § 98.233).
(C) Report the isolation valve leakage emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-23 and Equation W-24 of § 98.233).
(iv) Report total annual compressor emissions from all modes of operation (refer to Equation W-24 of § 98.233).
(v) For centrifugal compressors in onshore petroleum and natural gas production (refer to Equation W-25 of § 98.233), report the following:
(A) Count of compressors.
(B) Report emissions (refer to Equation W-25 of § 98.233) collectively.
(14) For reciprocating compressors:
(i) For reciprocating compressors rod packing emissions with or without a vent in operating mode, report the following:
(A) Annual throughput in million scf, use an engineering calculation based on best available data.
(B) Total time in hours the reciprocating compressor is in operating mode.
(C) Report rod packing emissions for compressors measured (refer to Equation W-26 of § 98.233) and for compressors not measured (refer to Equation W-27 and Equation W-28 of § 98.233).
(ii) For reciprocating compressors blowdown vents not manifold to rod packing vents, in operating and standby pressurized mode (refer to Equations W-26 through W-28 of § 98.233), report the following:
(A) Total time in hours the compressor is in standby, pressurized mode.
(B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to § 98.233, Equation W-28).
(C) Report blowdown vent emissions when in operating and standby pressurized modes (refer to Equation W-27 and Equation W-28 of § 98.233).
(iii) For reciprocating compressors in not operating, depressurized mode (refer to Equations W-26 through W-28 of § 98.233), report the following:
(A) Total time the compressor is in not operating, depressurized mode.
(B) Reporter emission factor for isolation valve emissions in not operating, depressurized mode in cubic feet per hour (refer to Equation W-28 of § 98.233).
(C) Report the isolation valve leakage emissions in not operating, depressurized mode.
(iv) Report total annual compressor emissions from all modes of operation (refer to Equation W-27 and Equation W-28 of § 98.233).
(v) For reciprocating compressors in onshore petroleum and natural gas production (refer to Equation W-29 of § 98.233), report the following:
(A) Count of compressors.
(B) Report emissions collectively.
(15) For each component type (major equipment type for onshore production) that uses emission factors for estimating emissions (refer to § 98.233(q) and (r))
(i) For equipment leaks found in each leak survey (refer to § 98.233(q)), report the following:
(A) Total count of leaks found in each complete survey listed by date of survey and each component type for which there is a leaker emission factor in Tables W-2, W-3, W-4, W-5, W-6, and W-7 of this subpart.
(B) For onshore natural gas processing, range of concentrations of CH4 and CO2 (refer to Equation W-30 of § 98.233).
(C) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas (refer to parameter GHGi in Equation W-30 of § 98.233), by component type.
(ii) For equipment leaks calculated using population counts and factors (refer to § 98.233(r)), report the following:
(A) For source categories § 98.230(a)(4), (a)(5), (a)(6), (a)(7), and (a)(8), total count for each component type in Tables W-2, W-3, W-4, W-5, and W-6 of this subpart for which there is a population emission factor, listed by major heading and component type.
(B) For onshore production (refer to § 98.230 paragraph (a)(2)), total count for each type of major equipment in Table W-1B and Table W-1C of this subpart, by facility.
(C) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas (refer to Equation W-31 of § 98.233), by component type.
(16) For local distribution companies, report the following:
(i) Total number of above grade T-D transfer stations in the facility.
(ii) Number of years over which all T-D transfer stations will be monitored at least once.
(iii) Number of T-D stations monitored in calendar year.
(iv) Total number of below grade T-D transfer stations in the facility.
(v) Total number of above grade metering-regulating stations (this count will include above grade T-D transfer stations) in the facility.
(vi) Total number of below grade metering-regulating stations (this count will include below grade T-D transfer stations) in the facility.
(vii) [Reserved]
(viii) Leak factor for meter/regulator run developed in Equation W-32 of § 98.233.
(ix) Number of miles of unprotected steel distribution mains.
(x) Number of miles of protected steel distribution mains.
(xi) Number of miles of plastic distribution mains.
(xii) Number of miles of cast iron distribution mains.
(xiii) Number of unprotected steel distribution services.
(xiv) Number of protected steel distribution services.
(xv) Number of plastic distribution services.
(xvi) Number of copper distribution services.
(xvii) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all above grade T-D transfer stations combined.
(xviii) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all below grade T-D transfer stations combined.
(xix) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all above grade metering-regulating stations (including T-D transfer stations) combined.
(xx) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all below grade metering-regulating stations (including T-D transfer stations) combined.
(xxi) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all distribution mains combined.
(xxii) Annual CO2 and CH4 emissions, in metric tons CO2e for each gas, from all distribution services combined.
(17) For each EOR injection pump blowdown (refer to Equation W-37 of § 98.233), report the following:
(i) Pump capacity, in barrels per day.
(ii) Volume of critical phase gas between isolation valves.
(iii) Number of blowdowns per year.
(iv) Critical phase EOR injection gas density.
(v) For each EOR pump, report annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas.
(18) For EOR hydrocarbon liquids dissolved CO2 for each sub-basin category (refer to Equation W-38 of § 98.233), report the following:
(i) Volume of crude oil produced in barrels per year.
(ii) Amount of CO2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions.
(iii) Report annual CO2 emissions at the sub-basin level, expressed in metric tons CO2e.
(19) For onshore petroleum and natural gas production and natural gas distribution combustion emissions, report the following:
(i) Cumulative number of external fuel combustion units with a rated heat capacity equal to or less than 5 mmBtu/hr, by type of unit.
(ii) Cumulative number of external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by type of unit.
(iii) Report annual CO2, CH4, and N2O emissions from external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, expressed in metric tons CO2e for each gas, by type of unit.
(iv) Cumulative volume of fuel combusted in external fuel combustion units with a rated heat capacity larger than 5 mmBtu/hr, by fuel type.
(v) Cumulative number of internal fuel combustion units, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr or 130 horsepower, by type of unit.
(vi) Report annual CO2, CH4, and N2O emissions from internal combustion units greater than 1mmBtu/hr, expressed in metric tons CO2e for each gas, by type of unit.
(vii) Cumulative volume of fuel combusted in internal combustion units with a rated heat capacity larger than 1 mmBtu/hr or 130 horsepower, by fuel type.
(d) Report annual throughput as determined by engineering estimate based on best available data for each industry segment listed in paragraphs (a)(1) through (a)(8) of this section.
(e) For onshore petroleum and natural gas production, report the best available estimate of API gravity, best available estimate of gas to oil ratio, and best available estimate of average low pressure separator pressure for each oil sub-basin category.
[75 FR 74488, Nov. 30, 2010, as amended at 76 FR 80587, Dec. 23, 2011]

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Title 40 published on 2013-07-01

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  • 2014-05-06; vol. 79 # 87 - Tuesday, May 6, 2014
    1. 79 FR - Greenhouse Gas Reporting Program: Final Amendments and Confidentiality Determinations for Subpart I
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      ENVIRONMENTAL PROTECTION AGENCY
      40 CFR Part 98