5 Colo. Code Regs. § 1001-9-B-V

Current through Register Vol. 47, No. 24, December 25, 2024

Section 5 CCR 1001-9-B-V - (State Only) Oil and Natural Gas Operations Emissions Inventory

V.A. Applicability

V.A.1. On or before June 30th, 2021 (and on June 30th each year thereafter), the owner or operator of oil and natural gas operations and equipment at or upstream of a natural gas processing plant in Colorado must submit a single annual report that includes actual emissions and specified information in the Division-approved report format.

V.A.2. On or before June 30th, 2022 (and on June 30th each year thereafter), the owner or operator or class II disposal well facilities that are not subject to reporting under Section IV. must submit a single annual report that includes actual emissions and specified information in the Division-approved report format.

V.B. General reporting requirements

V.B.1. The following information must be reported in accordance with Section V.A.

V.B.1.a. Company name, physical street address, and name and contact information of the company representative, for reporting purposes.

V.B.1.b. The date of submittal and the year covered by the report.

V.B.1.c. A list of the activities or equipment, as specified in Section V.C., for which emissions are reported. Beginning with the June 2022 report for the calendar year 2021, owners or operators must include whether the activities or equipment are located in a disproportionately impacted community.

V.B.1.d. Beginning with the June 2022 report for calendar year 2021, for well production facilities, a list of each well production facility, all associated wells by API number and associated location ID as assigned by the Colorado Oil and Gas Conservation Commission, and the total calendar year production of hydrocarbon liquids, and natural gas as well as throughput of produced water.

V.B.1.e. Beginning with the June 2021 report for calendar year 2020 through the June 2024 report for calendar year 2023:

V.B.1.e.(i) The company's monthly actual emissions of volatile organic compounds (VOC), oxides of nitrogen (NOx), nitrous oxide (N2O), carbon dioxide (CO2), carbon monoxide (CO), methane, and ethane for each month of May through September, in accordance with Division- accepted calculation methods.

V.B.1.e.(ii) The company's annual actual emissions of VOCs, NOx, N2O, CO2, CO, methane, and ethane for the entire calendar year, in accordance with Division-accepted calculation methods.

V.B.1.f. Beginning with the June 2025 report for calendar year 2024, the company's monthly actual emissions of VOCs, NOx, N2O, CO2, CO, methane, and ethane, in accordance with Division-accepted calculation methods.

V.B.1.g. The actual emissions of VOCs, NOx, N2O, CO2, CO, methane, and ethane for each activity or equipment listed in Section V.C. per facility, or per pipeline between facilities where the pipeline is not located at a stationary source, in accordance with Division- accepted calculation methods.

V.B.1.g.(i) Beginning with the June 2021 report for calendar year 2020 through the June 2024 report for calendar year 2023:

V.B.1.g.(i)(A) The report must include the actual emissions from each activity or equipment per month for each month of May through September.

V.B.1.g.(i)(B) The report must include the actual emissions from each activity or equipment for the entire calendar year.

V.B.1.g.(ii) Beginning with the June 2025 report for calendar year 2024, the report must include the monthly actual emission from each activity or equipment.

V.B.1.h. Beginning with the June 2022 report for calendar year 2021 through the June 2023 report for calendar year 2022, if the emissions reported for any activities or equipment, as specified in Section V.C., are calculated using a method other than what was used to report to the U.S. EPA under the federal Greenhouse Gas Reporting Program ( 40 CFR Part 98) for the same activity or equipment, the owner or operator must submit supporting documentation with the annual report that includes the emissions information reported to the EPA, an explanation of the difference in emissions reported to the Division, the emission calculation method(s) used to report to the Division, and a justification and supporting documentation for using a method other than that for the Greenhouse Gas Reporting Program. If the Division determines that the use of a different calculation method was not justified, the owner or operator must revise the report accordingly, to use the same calculation method as that reported under the federal Greenhouse Gas Reporting Program or other Division-approved method.

V.B.1.i. Emission factors, beginning with the June 2022 report for calendar year 2021, where emission factors are used to calculate emissions reported pursuant to Section V.B.1.

V.B.1.i.(i) Where the Division has published a default emission factor, owners or operators submitting reports under this section must use the state default factor or other Division- accepted emission factor.

V.B.1.i.(ii) Owners or operators using a site-specific emission factor must submit documentation to the Division supporting the use of that emission factor with the first annual emission report in which that site-specific emission factor is used (the calendar year 2021 report will be considered the first report for purposes of this section). If subsequent annual emission reports use the same emission factor, operators do not need to resubmit the supporting documentation.

V.B.1.i.(iii) Owners or operators using a site-specific emission factor must conduct a gas speciation analysis, a pressurized liquid sampling method, or another Division-accepted analytical method every five (5) years to verify the ongoing accuracy of the site-specific emission factor pursuant to a Division-accepted sampling method or protocol.

V.B.1.j. A certification by the company representative that supervised the development and submission of the inventory report that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete.

V.B.2. The owner or operator must submit a revised annual report after discovering that an annual report submitted within the previous two (2) years contained one or more substantive errors. A substantive error is a mass of emissions of any individual pollutant subject to reporting under Section V. that is at least 10% higher or lower than the mass of emissions of the pollutant reported across the owner or operator's activity or equipment, as listed in Section V.C., in Colorado. A refinement of or improvement to an emissions estimation technique or emission factor is not a substantive error but must be noted in the subsequent annual report after the refinement or improvement. Revised annual reports must be submitted by August 31 if the substantive error is discovered between January 1 and June 30, and by February 28 if the substantive error is discovered between July 1 and December 31 of the preceding calendar year.

V.C. Beginning July 1, 2020, and each calendar year thereafter, owners or operators must maintain the following information for inclusion in the annual report, except that beginning January 1, 2021, owners or operators must maintain the information described in Sections V.C.2.g. and V.C.2.h. Beginning May 1, 2021, owners or operators of class II disposal well facilities must maintain the following information for inclusion in the annual report.

V.C.1. AIRS number of the activity or equipment and associated facility or pipeline (if a pipeline between facilities) location, including latitude and longitude coordinates. If the activity or equipment does not have an AIRS number, a description of the activity or equipment.

V.C.2. Actual emissions from each activity or equipment listed, unless otherwise specified in the Division-approved report format, and the emission factor(s), assumptions, calculation methodology used to calculate the emissions, and other supporting information on the Division-approved form.

V.C.2.a. Abnormal events, except those reported as malfunctions under the Common Provisions or in another activity or equipment.

V.C.2.b. Acid gas removal units.

V.C.2.c. Associated gas venting and flaring, aggregated per facility. Beginning with the June 2023 report for calendar year 2022, owners or operators must measure or estimate the volume of natural gas that is vented or flared during drilling, completion, and production operations.

V.C.2.d. Blowdowns from facility equipment or piping where the physical volume of the piping between isolation valves is greater than or equal to 50 cubic feet, aggregated per activity below per facility. Beginning with the June 2024 report for calendar year 2023, owners or operators must report this information for all blowdowns from facility equipment and piping, where the physical volume between isolation valves is greater than or equal to 1 cubic foot.

V.C.2.d.(i) Pipeline venting within the facility boundary.

V.C.2.d.(ii) Compressors.

V.C.2.d.(iii) Scrubbers/strainers.

V.C.2.d.(iv) Pig launchers and receivers, through the June 2022 report for calendar year 2021.

V.C.2.d.(v) Emergency shutdowns (regardless of equipment type).

V.C.2.d.(vi) Through the June 2023 report (for calendar year 2022), all other equipment (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) with a physical volume between isolation valves greater than or equal to 50 cubic feet.

V.C.2.d.(vii) Beginning with the June 2024 report for calendar year 2023, all other equipment (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels), where the physical volume between isolation valves is greater than or equal to 1 cubic foot.

V.C.2.d.(viii) Beginning with the June 2024 report for calendar year 2023, best practices employed pursuant to Section II.H.4.

V.C.2.e. Boilers.

V.C.2.f. Centrifugal compressor leaks or vents, aggregated per facility. Beginning with the June 2025 report for calendar year 2024, centrifugal compressor leaks or vents must be aggregated per compressor.

V.C.2.g. Class II disposal well facility fluids accepted for injection. Owners or operators will take periodic, representative samples of the liquids for estimating emissions for the annual report.

V.C.2.h. Class II disposal well facility produced water ponds.

V.C.2.i. Drilling mud and mud pits.

V.C.2.j. Flares and enclosed combustion devices, where not otherwise reported in the emissions of another emissions source category.

V.C.2.k. Fugitive emissions from components, aggregated per facility. Beginning with the June 2022 report for calendar year 2021, gas composition data and component counts used in fugitive emissions calculations must be provided.

V.C.2.l. Hydrocarbon liquid storage tanks.

V.C.2.m. Hydrocarbon liquid loadout.

V.C.2.n. Maintenance and safety, where not otherwise reported in the emissions of another emissions source category. Beginning with the June 2023 report for calendar year 2022, owners or operators must report the basis for each maintenance or safety event.

V.C.2.o. Natural gas dehydration (glycol and desiccant).

V.C.2.p. Natural gas pneumatic controllers, aggregated per facility. Pneumatic controllers at the wellhead must be aggregated with the associated facility or be reported pursuant to a different Division-approved format.

V.C.2.q. Natural gas pneumatic pumps, aggregated per facility. Pneumatic pumps at the wellhead must be aggregated with the associated facility or be reported pursuant to a different Division-approved format.

V.C.2.r. Non-road internal combustion engines.

V.C.2.s. Pigging operations, including pig launchers and receivers. Beginning with the June 2023 report for calendar year 2022, emissions from pigging operations must be separately identified in the annual report from other operational activities, and aggregated by pigging unit.

V.C.2.s.(i) Beginning with the June 2024 report for calendar year 2023, capture or control methods or best practices employed pursuant to Sections II.H.1., II.H.2., or II.H.4. per pigging unit.

V.C.2.t. Pipeline segments between facilities.

V.C.2.u. Process heaters.

V.C.2.v. Produced water storage tanks.

V.C.2.w. Produced water loadout.

V.C.2.x. Reciprocating compressor leaks or vents, aggregated per facility. Beginning with the June 2023 report for calendar year 2022, reciprocating compressor leaks or vents must be aggregated per compressor.

V.C.2.y. Separators (e.g., two-phase separators, three-phase separators, high/low pressure separators, heater-treaters, vapor recovery towers, etc.). Beginning with the June 2022 report for calendar year 2021, stages of separation must be identified.

V.C.2.z. Stationary combustion turbines.

V.C.2.aa. Stationary compression ignition internal combustion engines.

V.C.2.bb. Stationary spark ignition internal combustion engines.

V.C.2.cc. Temporary completion and/or workover equipment (e.g., tanks).

V.C.2.dd. Thermal oxidizing units, where not otherwise reported in the emissions of another emissions source category.

V.C.2.ee. Well completions (includes flowback).

V.C.2.ff. Well workovers.

V.C.2.gg. Wellhead bradenhead.

V.D. Annual information reporting

V.D.1. Beginning in 2022, and each calendar year thereafter, the Division must prepare and send an annual information report to the Commission and the Colorado Oil and Gas Conservation Commission. The report must include:

V.D.1.a. Summary and analysis of oil and gas emissions data received or produced by the Division, including but not limited to

V.D.1.a.(i) Oil and gas annual emissions reporting under Section V.;

V.D.1.a.(ii) An update on the Division's leak detection and repair program, including a summary of information reported under Section II.E., as well as the results of any aerial and ground-based surveys performed by or at the direction of the Division;

V.D.1.a.(iii) Data collected from early production operations monitoring data reported to the Division under Section VI.; and

V.D.1.a.(iv) Greenhouse gas intensity plans and annual verifications submitted pursuant to Sections VIII.E. and VIII.G., specifically regarding the technologies and measures employed to reduce emissions from oil and gas production.

V.D.1.b. An evaluation of the progress toward the goals set forth in the Greenhouse Gas Pollution Reduction Roadmap; and any initiatives developed by the Division to achieve Colorado's statewide greenhouse gas emission reductions, and the role of oil and the role of oil and gas operations in achieving the reduction targets for the oil and gas sector;

V.D.1.c. Information regarding ambient air quality standard attainment, trends, and contributions from oil and gas operations, including ground-level ozone ambient air quality standards as presented to the Commission during the annual ozone presentation;

V.D.1.d. A summary of information collected pursuant to the community-based air toxics monitoring program performed by the Division under § 25-7-141(6), CRS;

V.D.1.e. Opportunities for inter-agency coordination, including workgroups, or basin-wide, statewide, or other regional studies to evaluate and address air quality issues related to oil and gas production; and

V.D.1.f. Additional information requested by the Commission or that the Division determines is relevant to achieving the state's greenhouse gas emission reduction targets or ozone attainment.

V.D.2. When transmitting information to the Colorado Oil and Gas Conservation Commission pursuant to Section V.D.1., the Division must make the report available to the public on the Division's website.

V.D.3. The Division must include the relevant annual information provided to the Colorado Oil and Gas Conservation Commission as part of the Division's report submitted every odd-numbered year to the General Assembly pursuant to § 25-7-105(1)(e)(V)), CRS. The Division must also submit the Division's General Assembly report to the Colorado Oil and Gas Conservation Commission.

5 CCR 1001-9-B-V

46 CR 16, August 25, 2023, effective 9/14/2023

47 CR 02, January 25, 2024, effective 2/14/2024