5 Colo. Code Regs. § 1001-9-B-VIII

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

Section 5 CCR 1001-9-B-VIII - (State Only) Greenhouse Gas Intensity Program for Oil and Natural Gas Upstream Segment

VIII.A. Definitions

VIII.A.1. "Calendar year" means January 1 up through and including December 31 of the year.

VIII.A.2. "Certified third-party auditor" means a person tasked with performing an environmental audit of an operator's Oil and Natural Gas Annual Emission Inventory Reports (ONGAEIR). The certified third-party auditor must have expertise in the area of emission calculation methodologies. The certified third-party auditor must be qualified to perform such audits, as determined by the Division. The certified third-party auditor must not have supervised or been responsible for the ONGAEIR calculations, permitting, or compliance support for that operator being audited.

VIII.A.3. "Co-benefits" for this Section VIII. means the reduction of harmful air pollutants in disproportionately impacted communities.

VIII.A.4. "Commencement of operation" means when a source first conducts the activity that it was designed and permitted for. In addition, for oil and gas well production facilities, commencement of operation is the date any permanent production equipment is in use and product is consistently flowing to sales lines, gathering lines, or storage tanks from the first producing well at the stationary source, but no later than end of well completion operations (including flowback).

VIII.A.5. "Controlling interest" for this Section VIII. means an interest that provides a person, either directly or indirectly, the power to direct or cause the direction of the management and policies of another person, whether through ownership or voting securities, by contract, or otherwise.

VIII.A.6. "Direct measurement" means regional, local, stationary source, or air pollution source monitoring of methane emissions used to quantify emissions of greenhouse gasses.

VIII.A.7. "Disproportionately impacted community" (DI community) means census block groups designated as DI communities in CDPHE's draft Data Viewer for Disproportionately Impacted Communities in Colorado (as of December 17, 2021, at: https://cohealthviz.dphe.state.co.us/t/EnvironmentalEpidemiologyPublic/views/EJActDICommunities-Public/HB21-1266DICommunities?%3AshowAppBanner=false&%3Adisplay_count=n&%3AshowVizHome=n&%3Aorigin=viz_share_link&%3AisGuestRedirectFromVizportal=y&%3Aembed=y) consistent with 24-4-109(2)(b)(II), C.R.S. (2021). A complete list of these census block groups by 12-digit FIPS code will be maintained by the Division and made publicly available.

VIII.A.8. "Drill-out" means the process of removing the plugs placed during hydraulic fracturing or refracturing. Drill-out ends after the removal of all stage plugs and the initial wellbore clean-up.

VIII.A.9. "Drilling" or "drilled" means the process to bore a hole to create a well for oil and/or natural gas production.

VIII.A.10. "Flowback" means the process of allowing fluids and entrained solids to flow from a well following stimulation, either in preparation for a subsequent phase of treatment or in preparation for cleanup and placing the well into production. The term flowback also means the fluids and entrained solids flowing from a well after drilling or hydraulic fracturing or refracturing. Flowback ends when all temporary flowback equipment is removed from service. Flowback does not include drill-out.

VIII.A.11. "Greenhouse gas intensity" means the sum of preproduction emissions and production emissions in a calendar year in mtCO2e divided by the kBOE for that calendar year, calculated pursuant to Sections VIII.D. and VIII.F.

VIII.A.12. "Harmful air pollutants" for purposes of Section VIII. means pollutants designated by EPA as criteria pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate pollution (PM) (PM2.5 and PM10) and sulfur dioxide) or hazardous air pollutants.

VIII.A.13. "Hydraulic fracturing" means the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale, coal, and tight sand formations, that subsequently require flowback to expel fracture fluids and solids.

VIII.A.14. "Hydraulic refracturing" means conducting a subsequent hydraulic fracturing operation at a well that has previously undergone a hydraulic fracturing operation.

VIII.A.15. "Intensity operator" means a person or entity that operates upstream segment activities or equipment. For purposes of Section VIII., where a person or entity holds a controlling interest in more than one intensity operator, that person or entity is the intensity operator of all upstream segment activities and equipment in which that person or entity has a controlling interest.

VIII.A.16. "kBOE" means production of hydrocarbon liquids and natural gas, measured in thousands of barrels of oil equivalent.

VIII.A.17. "mtCO2e" means metric tons (mt) of carbon dioxide equivalent, using global warming potential values from the IPCC Fifth Assessment Report, 2014 (AR5).

VIII.A.18. "Majority operator" means

(1) an intensity operator with company-wide production in Colorado in calendar year 2022 of greater than or equal to 10,000 kBOE;

(2) a new to market operator whose first transaction(s) in Colorado is to purchase the assets of a majority operator;

(3) a new to market operator for which the total level of production from all assets acquired or developed in that calendar year exceeds 10,000 kBOE;

(4) a new to market operator who has not purchased assets from a majority or minority operator and who commences operation of a well production facility after January 1, 2023; and

(5) a minority operator that becomes a majority operator pursuant to Section VIII.B.6.

VIII.A.19. "Measurement-informed inventory" means the greenhouse gas emissions inventory from the Oil and Natural Gas Annual Emission Inventory Reports (ONGAEIR) informed by direct measurement and, optionally, parametric measurement.

VIII.A.20. "Measurement strategy" means the strategy that describes how an intensity operator uses direct measurement and, optionally, parametric measurement to inform reported greenhouse gas emissions in ONGAEIR.

VIII.A.21. "Midstream segment" means the oil and natural gas compression segment and the natural gas processing segment that are physically located in Colorado and that are upstream of the natural gas transmission and storage segment.

VIII.A.22. "Minority operator" means an intensity operator with company-wide production of hydrocarbon liquids and natural gas in Colorado in calendar year 2022 of less than 10,000 kBOE. Minority operator also means a new to market operator whose first transaction(s) in Colorado is to purchase the assets of a minority operator, as long as the total level of production from all assets acquired or developed by (in the case of new well production facilities) of the new to market operator in that calendar year does not exceed 10,000 kBOE.

VIII.A.23. "New to market operator" means an owner or operator that did not produce any oil or natural gas in Colorado in calendar years 2021 or 2022 or own or operate any well production facility in Colorado as of December 31, 2022. A new to market operator that becomes a majority operator as defined in Section VIII.A.16. or a minority operator as defined in Section VIII.A.18. is no longer a new to market operator.

VIII.A.24. "Oil and Natural Gas Annual Emission Inventory Reports (ONGAEIR)" means the annual emissions inventory reports required in Regulation Number 7, Part B, Sections II.G.3 and V for oil and gas segment emissions.

VIII.A.25. "Parametric Measurement" means regional, local, stationary source, or air pollution source monitoring of pressure, temperature, flow rate, control efficiency, or other operational characteristics used to inform quantification of greenhouse gas emissions.

VIII.A.26. "Preproduction emissions" means the greenhouse gas emitted from an oil or natural gas well and associated equipment and activities during the construction and operation of the oil or natural gas well until the well commences operation, including from the drilling through the hydrocarbon bearing zones, hydraulic fracturing or refracturing, drill-out, and flowback of the oil and/or natural gas well.

VIII.A.27. "Production emissions" means the greenhouse gas emitted from an oil or natural gas well and associated equipment and activities after the well commences operation.

VIII.A.28. "State default intensity verification factor" means the methane factor developed to account for the difference (if any) in monitored methane emissions and reported methane emissions and used in the calculation of greenhouse gas intensity.

VIII.A.29. "Upstream segment" means oil and natural gas exploration and production operations physically located in Colorado upstream of the midstream segment.

VIII.A.30. "Well production facility" means all equipment at a single stationary source directly associated with one or more oil wells or natural gas wells upstream of the natural gas processing plant. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline.

VIII.B. Greenhouse gas intensity targets for the upstream segment.

VIII.B.1. Beginning January 1, 2023, intensity operators must participate in this greenhouse gas intensity program to reduce preproduction and production emissions in Colorado. An intensity operator that fails to achieve any of the applicable targets in Section VIII.B. must achieve additional reductions in preproduction and/or production emissions in the subsequent calendar year to address the difference between the intensity operator's reported greenhouse gas intensity for that calendar year and the applicable target.

VIII.B.2. For calendar year 2025, intensity operators subject to Section VIII.B.1. must achieve the following greenhouse gas intensity targets for preproduction and production emissions.

VIII.B.2.a. Majority Operator: 10.94 mtCO2e/kBOE.

VIII.B.2.b. Minority Operator: 34.39 mtCO2e/kBOE.

VIII.B.3. For calendar year 2027, intensity operators subject to Section VIII.B.1. must achieve the following greenhouse gas intensity targets for preproduction and production emissions.

VIII.B.3.a. Majority Operator: 8.46 mtCO2e/kBOE.

VIII.B.3.b. Minority Operator: 26.60 mtCO2e/kBOE.

VIII.B.4. For calendar year 2030, intensity operators subject to Section VIII.B.1. must achieve the following greenhouse gas intensity targets for preproduction and production emissions.

VIII.B.4.a. Majority Operator: 6.80 mtCO2e/kBOE.

VIII.B.4.b. Minority Operator: 21.38 mtCO2e/kBOE.

VIII.B.5. In calendar years 2026, 2028, and 2029, intensity operators subject to Section VIII.B.1. must achieve a greenhouse gas intensity less than or equal to the applicable preceding year target in Sections VIII.B.2. and VIII.B.3. (e.g., for calendar year 2026 achieve at least the target for calendar year 2025).

VIII.B.6. If, in any calendar year beginning 2023, a minority operator

VIII.B.6.a. Has production of greater than or equal to 10,000 kBOE or

VIII.B.6.b. Has production that represents an increase over production in the prior calendar year by greater than or equal to 2,500 kBOE (e.g., if production is 2,500 kBOE higher in 2023 than it was in 2022), then

VIII.B.6.c. Beginning the calendar year after the applicable circumstances under Sections VIII.B.6.a. or VIII.B.6.b., unless otherwise approved by the Division, the minority operator becomes a majority operator and must comply with the applicable majority operator greenhouse gas intensity targets for all its upstream segment operations for that year and all remaining years through 2030.

VIII.B.7. Acquisitions. Except as provided, if an owner or operator acquires or takes over operation of an oil or natural gas well in Colorado after January 1, 2025, that owner or operator must meet the greenhouse gas intensity targets in Sections VIII.B.2. through VIII.B.5. applicable to the intensity operator acquiring the assets.

VIII.B.7.a. If a majority operator merges with, acquires, or takes over operation of an oil or natural gas well in Colorado from a minority operator on or after January 1, 2025, the majority operator (or surviving entity) must at least comply with the applicable minority operator greenhouse gas intensity target for the preproduction and production emissions from the acquired well(s) for the calendar year of the acquisition. Beginning with the calendar year after the acquisition, the applicable majority owner or operator must comply with the applicable majority operator greenhouse gas intensity targets for the preproduction and production emissions from all its upstream segment operations, including the acquired well(s).

VIII.B.7.b. If a minority operator acquires or takes over operation of an oil or natural gas well in Colorado from a majority operator on or after January 1, 2025, the minority operator must at least comply with the applicable minority operator greenhouse gas intensity target for the preproduction and production emissions from the acquired well(s) for the calendar years of and after the acquisition, after which the minority operator greenhouse gas intensity targets apply to all assets of the minority operator, including the acquired assets (unless the minority operator has become a majority operator).

VIII.C. New facility intensity targets.

VIII.C.1. Beginning January 1, 2023, intensity operators of well production facilities that commence operation after December 31, 2022, must also meet the new facility intensity target(s) for those facilities as set forth in Sections VIII.C.2. through VIII.C.4. in the calendar year of and the calendar year after the well production facility commences operation. These targets are in addition to the targets applicable to all of the intensity operator's upstream segment operations as specified in Section VIII.B.

VIII.C.1.a. For purposes of Section VIII.C., "new facility intensity" means the production emissions in CO2e from all well production facilities commencing operation in a calendar year divided by the production of hydrocarbon liquid and natural gas from those facilities in kBOE for that calendar year.

VIII.C.2. For calendar years 2023 through 2025, the new facility intensity target is 8.59 mtCO2e/kBOE, unless the well production facility is located in the 8-hour Ozone Control Area and in a disproportionately impacted community, then the new facility intensity target is 7.7 mtCO2e/kBOE.

VIII.C.3. For calendar years 2026 through 2027, the new facility intensity target is 6.64 mtCO2e/kBOE, unless the well production facility is located in the 8-hour Ozone Control Area and in a disproportionately impacted community, then the new facility intensity target is 6.0 mtCO2e/kBOE.

VIII.C.4. For calendar years 2028 through 2030, the new facility intensity target is 5.34 mtCO2e/kBOE, unless the well production facility is located in the 8-hour Ozone Control Area and in a disproportionately impacted community, then the new facility intensity target is 4.8 mtCO2e/kBOE.

VIII.D. Accounting for production kBOE, preproduction emissions, and production emissions.

VIII.D.1. Production can only be allocated to one intensity operator for the same time period. Intensity operators must account for production from all oil or natural gas wells and well production facilities in which the intensity operator holds the controlling interest. Intensity operators must account for production during the time in which the intensity operator holds that controlling interest.

VIII.D.2. Intensity operators must calculate kBOE by adding the production of hydrocarbon liquids in thousand barrels to the proportion of natural gas (calculated by dividing the million standard cubic feet (MMscf) volume of natural gas produced by the conversion rate of 5.8 MMscf/kBOE).

VIII.D.3. The intensity operator that reports the preproduction emissions and production emissions for upstream segment activities and equipment must report the kBOE associated with those activities and equipment.

VIII.E. Intensity operator greenhouse gas intensity plans.

VIII.E.1. Greenhouse gas intensity plans must be submitted on a Division-approved format and must contain, at a minimum

VIII.E.1.a. An identification of all the intensity operator's well production facilities, including facility name; facility AIRS ID, or facility location if the facility does not have an AIRS ID; entity listed as the operator for all well production facilities covered by the greenhouse gas intensity plan for which production is included as specified under Section VIII.D.1.; and an identification of which facilities are located within a disproportionately impacted community.

VIII.E.1.b. The intensity operator's greenhouse gas intensity company-wide and per well production facility for the preceding calendar year, including intensity calculation methodology in accordance with Section VIII.F2.

VIII.E.1.c. A list and description of the best management practices (BMPs), control methods, emission reduction strategies, and technologies the intensity operator intends to use to meet the applicable targets in Section IV.B.2. on a site-specific basis.

VIII.E.1.d. An estimate of the greenhouse gas emission reductions that each type of BMP, control method, emission reduction strategy, or technology is expected to achieve on a company-wide mass basis and on a company-wide greenhouse gas intensity basis, including calculation methods.

VIII.E.1.e. A description of which BMPs, control methods, emission reduction strategies, and technologies will be deployed in disproportionately impacted communities, and a demonstration that intensity operators will prioritize co-benefits.

VIII.E.2. Greenhouse gas intensity plan submittal deadlines.

VIII.E.2.a. By August 31, 2023, each intensity operator subject to Section VIII.B.1. must submit to the Division a proposed greenhouse gas intensity plan demonstrating how the intensity operator intends to meet the applicable greenhouse gas intensity targets in Section VIII.B.2.

VIII.E.2.b. By June 30, 2026, each intensity operator subject to Section VIII.B.1. must submit to the Division a greenhouse gas intensity plan demonstrating how the intensity operator will meet the applicable greenhouse gas intensity targets in Section VIII.B.3.

VIII.E.2.c. By June 30, 2028, each intensity operator subject to Section VIII.B.1. must submit to the Division a greenhouse gas intensity plan demonstrating how the intensity operator will meet the applicable greenhouse gas intensity targets in Section VIII.B.4.

VIII.E.3. Asset transfer updates.

VIII.E.3.a. Section VIII.E.3. applies whenever ownership or operation of an oil or natural gas well or well production facility is transferred after August 31, 2024. The operator taking over operation of the oil or natural gas well or well production facility is referred to herein as the "acquiring operator". The intensity operator from whom ownership or operation is transferred is referred to as the "selling operator."

VIII.E.3.b. If the transaction involves any well production facility for which the selling operator's greenhouse gas intensity plan submitted under Section VIII.E.2. provides for implementation of any BMP, control method, emission reduction strategy, or technology, then within thirty (30) days of closing of the transaction.

VIII.E.3.b.(i) The selling operator must submit an update to its greenhouse gas intensity plan that:

VIII.E.3.b.(i)(A) Identifies each well production facility transferred (name and AIRS ID, if applicable), the name of the acquiring operator, and the date of closing of the transaction.

VIII.E.3.b.(i)(B) Includes a quantification of the emission reductions that would have been achieved at each well production facility involved in the transaction under the greenhouse gas intensity plan consistent with the calculation methods used in Section VIII.E.1.d.

VIII.E.3.b.(i)(C) Includes a demonstration that the selling operator will still meet its greenhouse gas intensity targets and identifies any additional BMPs, control method, emission reduction strategy, and technologies consistent with Section VIII.E.1.

VIII.E.3.b.(ii) The acquiring operator must submit an update to its greenhouse gas intensity plan (or, in the event the acquiring operator is also a new to market operator, the acquiring operator must submit a new greenhouse gas intensity plan) that, for each well production facility involved in the transaction

VIII.E.3.b.(ii)(A) Identifies the well production facility transferred (name and AIRS ID, if applicable), the name of the selling operator, and the date of closing of the transaction.

VIII.E.3.b.(ii)(B) Commits to implementing the same BMP, control method, emission reduction strategy, and technology provided for in the selling operator's plan on the same schedule; or

VIII.E.3.b.(ii)(C) Quantifies the emission reductions that would have been achieved under the selling operator's greenhouse gas intensity plan consistent with the calculation methods used in Section VIII.E.1.d. and identifies how the acquiring operator will achieve equal or greater emission reductions at the same or other well production facilities involved in the transaction (or, if approved by the Division, at other of the acquiring operator's well production facilities) on the same schedule.

VIII.F. Verification through achievement of a measurement-informed inventory.

VIII.F.1. [Repealed as on July 21, 2023]

VIII.F.2. Applicability

VIII.F.2.a. Intensity operators must comply with Section VIII.F.3. to calculate greenhouse gas intensity and new facility intensity for:

VIII.F.2.a.(i) Greenhouse Gas Intensity Plans submitted pursuant to Section VIII.E.2.b and VIII.E.2.c; and

VIII.F.2.a.(ii) Annual reports as required in VIII.G. submitted in 2026 through 2031.

VIII.F.2.b. The requirements of Section VIII.F.2.a do not apply to calculations of new facility greenhouse gas intensity pursuant to Section VIII.C for 2023 and 2024 as reported in annual reports as required in VIII.G. submitted in 2024 and 2025.

VIII.F.3. Greenhouse Gas Intensity Verification Calculation Methodology to Demonstrate Compliance with the Greenhouse Gas Intensity Targets in Sections VIII.B and VIII.C.

Intensity operators must comply with either Section VIII.F.3.a or Section VIII.F.3.b to develop a measurement-informed inventory used to demonstrate compliance with the intensity operator's required greenhouse gas intensity.

VIII.F.3.a. State Default Intensity Verification Factor

Starting in 2024, by December 31 of each year through 2029, the Division will publish one or more state default intensity verification factors valid for the following calendar year. Intensity operators must apply a state default intensity verification factor to their ONGAEIR methane emissions, as outlined by the Division, unless the operator elects to use an operator-specific program pursuant to Section VIII.F.3.b.

VIII.F.3.b. Operator-Specific Programs

As an alternative to the state default intensity verification factor outlined in Section VIII.F.3.a., operators may utilize an operator-specific program. The operator-specific program must include:

VIII.F.3.b.(i) A measurement strategy.

VIII.F.3.b.(i)(A) For calendar years 2025 and 2026, intensity operators must use a measurement strategy developed by the Division. Starting in calendar year 2027, operators may use a measurement strategy developed by either the Division or the intensity operator.

VIII.F.3.b.(i)(A)(1) The Division will develop, in accordance with VIII.F.4., a list of approved measurement strategies that are sufficient to achieve a robust measurement-informed inventory, which will be published in the Intensity Verification Protocol.

VIII.F.3.b.(i)(A)(2) Intensity operators may develop their own measurement strategy for use beginning in calendar year 2027. Intensity operators must submit their measurement strategy to the Division for review and approval by March 31 of the year prior to which the intensity operator intends to implement the measurement strategy. The Division must review operator-developed measurement strategies, and within 90 days, may either approve the strategy, require revisions to the strategy, or deny the strategy. If the Division denies approval of the measurement strategy, the intensity operator may either use the state default intensity verification factor or a Division-developed measurement strategy.

VIII.F.3.b.(i)(B) The measurement strategy must define how direct measurement and, where it is used, parametric measurement informs reporting of emissions, considering: the appropriateness of the selected measurement technology or methodology, including the minimum detection limit; representativeness of monitoring sites; emission rates and probability of detection of the monitoring technology; variability of emissions over time; and other reasonable and necessary monitoring considerations as determined by the Division.

VIII.F.3.b.(i)(C) The measurement strategy must include direct measurements at the site-level.

VIII.F.3.b.(i)(D) The direct measurement technology(ies) used across the intensity operator's assets must be fit for purpose, capture a sufficient portion of expected emissions, and be validated with appropriate testing.

VIII.F.3.b.(i)(E) The measurement strategy must include an operation and maintenance plan in accordance with the manufacturer recommendations for monitoring technology or as developed by the operator to ensure the accuracy of the measurement strategy.

VIII.F.3.b.(i)(F) Measurement strategies must be reviewed annually and updated as necessary to demonstrate compliance with Section VIII.F.3.b.(i).

VIII.F.3.b.(ii) An audit of the measurement-informed inventory for calendar years 2025, 2027, and 2030. No later than December 31 of the following calendar year, a certified third party auditor will provide a summarized report of their findings and recommendations as relates to the reporting of greenhouse gas emissions. The audit must include review of:

VIII.F.3.b.(ii)(A) Greenhouse gas emission calculations reported in ONGAEIR,

VIII.F.3.b.(ii)(B) Monitoring records collected under the measurement strategy required in VIII.F.3.b.(i),

VIII.F.3.b.(ii)(C) Records maintained in support of monitoring, testing, and reporting requirements of Regulation Number 7 that affect the operator's ONGAEIR.

VIII.F.3.b.(iii) The Division may review operator-specific programs, and may either require revisions to the program or deny the program and require an operator to use the state default intensity verification factor.

VIII.F.4. Intensity Verification Protocol

The Division will create and maintain a protocol for intensity verification with the information contained in these Sections VIII.F. and VIII.G. The Division will review the protocol annually, and identify needed revisions. Any revisions must be published by June 30 of the calendar year preceding the verification year. Upon any revisions to the protocol beyond those that are administrative in nature, the Division must provide an opportunity for public participation. This includes:

VIII.F.4.a. A minimum of a 30-day public comment period.

VIII.F.4.b. A minimum of 2 public meetings for presentation of revisions and/or to accept public feedback.

VIII.F.5. Recordkeeping

VIII.F.5.a. Where Section VIII.F.3.b. applies, owners or operators must maintain records, including the measurement strategy and any subsequent updates and make them available to the Division upon request. In addition, for a period of five years, owners or operators must maintain the following records, or contract for access to such records as applicable, and make them available to the Division upon request:

VIII.F.5.a.(i) Records created by the measurement strategy, including the data associated with each monitoring technology and/or the monitoring report from the monitoring contractor.

VIII.F.5.a.(ii) Records of calibration of any equipment used in the measurement strategy, including the date(s) of the calibration.

VIII.F.5.a.(iii) Records of maintenance of any equipment used in the measurement strategy, including the date(s) and a description of the corrective actions.

VIII.F.5.b. Where Section VIII.F.3.b. applies, owners or operators must maintain the following records for a minimum of 5 years. Records must be made available to the Division upon request.

VIII.F.5.b.(i) Records of the complete submission to the certified third-party auditor.

VIII.F.5.b.(ii) Records of reports created by certified third-party auditors.

VIII.F.5.b.(iii) Records of actions taken in response to third-party audit.

VIII.G. Reporting

VIII.G.1. Summary of measurement strategy

By September 30 of 2024 through 2029 for the next calendar year, intensity operators must notify the Division if the intensity operator intends to utilize an operator-specific program in Section VIII.F.3.b., and if so, submit to the Division a summary of the measurement strategy including all information identified by the Division in the Intensity Verification Protocol. Operators that submitted a notification of their intent to use an operator-specific program may revert back to using the state-default intensity verification factor(s) or a Division-developed measurement strategy for a given year, with Division approval, after a showing of good cause.

VIII.G.2. Annual verifications

By June 30 of 2024 through 2031 for the previous calendar year, intensity operators must submit annual verifications on a Division-approved form in accordance with Section VIII.F.2. to the Division summarizing the intensity operator's greenhouse gas intensity plan implementation during the preceding calendar year. For the annual verifications due in 2024 and 2025, the items in Sections VIII.G.2.a. through VIII.G.2.j. are required only as they are applicable to new facility intensity for calendar years 2023 and 2024. The annual verification must include, at a minimum:

VIII.G.2.a. The intensity operator's implementation of the types of BMPs, control measures, emission reduction strategies, and technologies in its greenhouse gas intensity plan, on a site-specific basis (by location name and AIRS ID, if applicable, and whether the site is located within a disproportionately impacted community) for each BMP, control method, emission reduction strategy, and technology implemented.

VIII.G.2.b. If applicable, an identification of new well production facilities subject to Section VIII.C. commencing operation in that calendar year.

VIII.G.2.c. If applicable, the intensity operator's implementation of BMPs, control measures, emission reduction strategies, and technologies to achieve the new facility intensity target at all sites subject to Section VIII.C. on a site-specific basis (by location name and AIRS ID, if applicable.

VIII.G.2.d. Instances of departure from the intensity operator's greenhouse gas intensity plan, reason(s) for departure, and any modifications of the applicable element(s) of the BMP plan.

VIII.G.2.e. Use of any alternative emission reduction approaches not specified in the intensity operator's greenhouse gas intensity plan.

VIII.G.2.f. A demonstration that emission reductions were prioritized in disproportionately impacted communities, including a quantification of co-benefits achieved.

VIII.G.2.g. Identification by location name, AIRS ID (if applicable), well API number, and COGCC location ID (if applicable) of any oil or natural gas wells acquired or divested during the previous calendar year; the date of acquisition or divestment; and the name of the operator from which the well(s) were acquired or to whom the well(s) were divested.

VIII.G.2.h. A certification by a company representative with oversight over the operator's greenhouse gas intensity program that the annual verification is accurate and complete, to the best of the representative's knowledge and, if applicable, that measures identified in an asset transfer update submitted under Section IV.E.3. have been implemented as described therein.

VIII.G.2.i. The annual company-wide and new facility greenhouse gas intensity.

VIII.G.2.j. If applicable, whether the operator utilized the state default intensity verification factor in Section VIII.F.3.a. or an operator-specific program in Section VIII.F.3.b.

VIII.G.3. Updated Greenhouse Gas Intensity Plan

By June 30, 2026 through 2031, if an intensity operator does not meet the required intensity target for the previous calendar year, the intensity operator must update their most recently submitted greenhouse intensity plan to demonstrate how the operator intends to meet its required intensity target and meet the additional reductions required by Section VIII.B.1. and submit that updated greenhouse gas intensity plan to the Division.

VIII.G.4. Operator-Specific Program Measurement Strategy

By June 30 of 2026 through 2031 for the preceding calendar year, where an intensity operator utilized an operator-specific GHG intensity verification program as allowed in Section VIII.F.3.b., the intensity operator must submit to the Division the following:

VIII.G.4.a. The measurement strategy including all information identified by the Division in the Intensity Verification Protocol.

VIII.G.4.b. An evaluation of the implementation of the measurement strategy, including all information identified by the Division in the Intensity Verification Protocol.

VIII.G.5. Operator-Specific Program Third-Party Audit Reports

Where the intensity operator utilized an operator-specific GHG intensity verification program as allowed in Section VIII.F.3.b., the intensity operator must submit to the Division a summarized report with a list of any findings of the certified third-party auditor that may indicate the ONGAEIR needs to be adjusted, along with any revisions the operator is making to address those findings. The report must also include the credentials and certification of the third-party auditor. The report is due by the following dates:

VIII.G.5.a. By December 31, 2026, for calendar year 2025,

VIII.G.5.b. By December 31, 2028, for calendar year 2027, and

VIII.G.5.c. By December 31, 2031, for calendar year 2030.

5 CCR 1001-9-B-VIII

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

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