Colorado’s methane multiplier changed sharply in one year, from a single statewide 1.164 to regional values of 2.2 to 2.7 [1]. The next factor is due by December 31, 2026, and applies to the 2027 reporting year [2]. In 2027 both intensity targets also tighten by about 23%. For an operator near its target, the factor can decide whether a year passes or triggers extra reductions the next year.
Colorado’s Oil and Gas Greenhouse Gas Intensity Program sits in Regulation 7 Part B Section VIII, the state’s air rule for oil and gas operations [3]. Regulation 7’s formal citation is 5 CCR 1001-9, its number in the Code of Colorado Regulations (CCR) [3]. The program sets declining targets for greenhouse gas (GHG) intensity, the heat-trapping gases an operator emits per unit of oil and gas produced [2]. It scales ONGAEIR methane (the Oil and Natural Gas Annual Emission Inventory Reports) by a state-published verification factor, unless the operator runs an operator-specific program [2].
The State Default Intensity Verification Factor, this post’s subject, is applied to reported methane to account for differences from monitored methane [1]. The Colorado Department of Public Health and Environment (CDPHE), the state agency that runs the program, publishes it [1].
The rule requires operators to apply the factor to their ONGAEIR methane, as outlined by the division [2]. In practice, the division applies it to reported and validated methane after submission, for operators without an operator-specific program [1]. The factor for the 2025 reporting year is 1.164, so verified methane is 16.4% higher than what operators reported [1].
This guide is for compliance managers at Colorado upstream operators who file ONGAEIR each year. It covers, in order, the program and its rule history, how the factor builds the intensity ratio, and the targets through 2030. It closes with the operator-specific alternative and four common questions. The post is the first in a three-part series: the second covers the default factor’s cost and the third the monitoring path.
What Is the Reg 7 Part B Section VIII GHG Intensity Program?
Colorado’s GHG Intensity Program sets declining greenhouse gas intensity targets for upstream oil and gas operations statewide [2]. The Air Quality Control Commission (AQCC), the board that adopts Colorado’s air rules, established the upstream GHG intensity requirements in December 2021 [4].
Its authority traces to Senate Bill 19-181, enacted in 2019 [5]. The Commission set the targets to achieve the reductions House Bill 21-1266 requires of upstream operations [3]. The intensity verification framework, including the state default verification factor, was adopted in July 2023 [4].
The verification factor is developed to account for any difference between the methane operators report and the methane that monitoring detects [1]. A synthesis led by scientists at the Environmental Defense Fund (EDF), an environmental advocacy group, found national supply-chain methane about 60% above the federal inventory [6]. That inventory is published by the Environmental Protection Agency (EPA), the federal environmental regulator [6].
The study put the production segment at about twice the inventory figure (Alvarez et al., 2018) [6]. Later aerial surveys found a larger gap still: a six-region average roughly three times the national government inventory estimate (Sherwin et al., 2024) [7]. Colorado built a regulatory structure that scales reported methane by a state factor reflecting the gap between monitored and reported emissions [2]. The resulting emissions, divided by production in kBOE, are then compared to an intensity target that steps down in 2027 and 2030 [2].
Who Must Comply
The program applies to intensity operators, meaning anyone who operates upstream oil and gas equipment or activities in Colorado [2]. Upstream means exploration and production, so midstream and downstream facilities fall outside the program’s scope [2]. Participation is mandatory: beginning January 1, 2023, intensity operators must participate, which means filing greenhouse gas intensity plans and annual verification reports [2].
How the Rule Has Changed Since 2019
Regulation 7 has been revised several times since the verification rule; the version in force today took effect July 15, 2026 [3]. A further revision adopted September 18, 2026 takes effect November 14, 2026 [8]. It aligns Regulation 7 with EPA’s methane emission guidelines for existing oil and gas sources [8].
The Section VIII text on Cornell LII still shows the version effective April 14, 2025 [2]. Read the version in force for your reporting year on the Secretary of State register.
| Date | Action | What it means for the factor |
|---|---|---|
| April 16, 2019 | Senate Bill 19-181 signed | Legislative authority the program traces to |
| December 2021 | AQCC adopts upstream GHG intensity requirements (in Regulation 22, moved to Regulation 7 in April 2023) | Sets the intensity targets |
| July 2023 | AQCC adopts the intensity verification rule | State default factor and operator-specific path |
| By December 31, 2024 | Deadline for CDPHE to publish the 2025 factor | 1.164 statewide |
| February 21, 2025 (effective April 14, 2025) | Regulation 7 revision | Section VIII text shown on Cornell LII |
| By December 31, 2025 | Deadline for CDPHE to publish the 2026 factors | Regional (2.2 to 2.7) and larger, informed by COBE |
| February 20, 2026 (effective April 14, 2026) | Regulation 7 revision | First target moves to 2030 for operators under 45 kBOE |
| May 22, 2026 (effective July 15, 2026) | Regulation 7 revision | Version in force until November 14, 2026 |
| September 18, 2026 (effective November 14, 2026) | Regulation 7 revision | Aligns the rule with EPA’s existing-source methane guidelines |
| By December 31, 2026 | CDPHE due to publish the 2027 factor | Applies to the 2027 reporting year |
How the Verification Factor Produces the Intensity Ratio
The intensity calculation can be read as three steps. Operators submit methane through ONGAEIR, the state factor scales it upward, and the result enters a ratio checked against the annual target [2].
In step one, operators calculate and submit facility-level methane emissions through the ONGAEIR process [9]. They calculate those totals with CDPHE’s published calculation methods and emission factors for each type of equipment and activity [9]. The ONGAEIR deadline is June 30 for the prior calendar year; for a walkthrough of what the filing involves, see the ONGAEIR annual report checklist [9].
Step 2: Multiply by the State Default Intensity Verification Factor
CDPHE publishes a State Default Intensity Verification Factor on its GHG intensity program page by December 31 each year [1]. Each publication applies to the following reporting year, and the series runs through December 31, 2029 [1].
The 2025 factor of 1.164 was due by December 31, 2024, to account for differences between monitored and reported methane [1]. METEC, the Methane Emissions Technology Evaluation Center, is Colorado State University’s methane test facility [10]. With CDPHE it ran the Colorado Ongoing Basin Emissions (COBE) study, a field campaign of aerial methane surveys [10]. Its final report, released in 2025, informs the 2026 factor rather than the 2025 value [10].
The factor for the 2026 reporting year was required to be published by December 31, 2025 [2]. CDPHE has since published the 2026 factors, and unlike the single statewide 1.164, they differ by region and are substantially larger. CDPHE’s program page lists 2.2 for the 9-County Front Range, 2.7 for the 3-County West Slope and 2.5 for the rest of the state [1].
The worked example that follows uses the 2025 statewide factor of 1.164 to show the mechanic. Operators without an operator-specific program apply the factor CDPHE publishes for the reporting year, which for 2026 varies by intensity region.
An operator reporting 500 metric tons of methane in ONGAEIR would calculate verified methane as 500 multiplied by 1.164, yielding 582 metric tons [2]. Those 582 metric tons, converted to mtCO2e with AR5 100-year warming potentials, replace the original 500 in the ratio’s emissions total [2]. A 16.4% adjustment may sound modest, but the 2026 regional factors raise reported methane by 120% to 170%. Because the factor raises the ratio’s methane component, any default-factor operator narrowly meeting a target, large or small, can be pushed over it.
Step 3: Intensity Ratio vs. Annual Target
The GHG intensity ratio divides a year’s preproduction and production emissions by its hydrocarbon liquid and natural gas production in kBOE [2]. Emissions are in metric tons of CO2 equivalent (mtCO2e), which weights methane by 100-year global warming potentials from the IPCC Fifth Assessment Report [2]. An operator that misses a target must achieve additional reductions in the following calendar year to address the difference [2].
The second post in this series covers what the default factor costs operators in practice and how that cost scales with production volume.
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What Are the Intensity Targets, and Can Operators Lower Their Factor?
Targets are set for 2025, 2027 and 2030, falling to 6.80 mtCO2e/kBOE for majority operators and 21.38 for minority operators [2]. Operators can replace the default factor with their own measurements through an operator-specific program [2].
The Intensity Target Schedule Through 2030
The regulation names explicit targets for 2025, 2027, and 2030, and holds the years in between at the previous target [2].
The targets set separate values for majority and minority operators, classed mainly by company-wide Colorado production in 2022 [2]. A majority operator generally had at least 10,000 kBOE of company-wide Colorado production in 2022; a minority operator had less [2]. Rules for new-to-market operators and production growth can also make an operator a majority operator [2]. Each class carries its own target, measured in metric tons of CO2e per thousand barrels of oil equivalent (mtCO2e/kBOE) [2].
| Compliance year | Majority operator (mtCO2e/kBOE) | Minority operator (mtCO2e/kBOE) | How the target is set |
|---|---|---|---|
| 2025 | 10.94 | 34.39 | Explicit target (VIII.B.2) |
| 2026 | 10.94 | 34.39 | At or below the 2025 target (VIII.B.5) |
| 2027 | 8.46 | 26.60 | Explicit target (VIII.B.3) |
| 2028 | 8.46 | 26.60 | At or below the 2027 target (VIII.B.5) |
| 2029 | 8.46 | 26.60 | At or below the 2027 target (VIII.B.5) |
| 2030 | 6.80 | 21.38 | Explicit target (VIII.B.4) |
A February 2026 rulemaking changed the timeline for the smallest operators [4]. An operator under 45 kBOE in 2025 has no 2025 target, and one under 45 kBOE in both 2026 and 2027 has no 2027 target [4]. 45 kBOE a year is roughly 123 barrels of oil equivalent per day, or 715 thousand cubic feet of gas per day at 5.8 MMscf/kBOE. Operators at 45 kBOE or more in those years keep the 2025 and 2027 targets; the 2030 target applies regardless of size [4].
The extra time changes the deadline, not the destination. Class follows 2022 production and new-to-market rules: a newcomer that begins operating after January 1, 2023 without buying assets is a majority operator [2]. The 45 kBOE threshold does not set the class: a small minority operator faces 21.38 mtCO2e/kBOE in 2030, and a small majority operator 6.80 [2]. Qualifying small operators gain time, not slack: the 2030 target still applies in full, with no interim targets to pace the reduction.
Targets step down in 2027 and 2030, and a factor above 1 raises calculated intensity, so the factor tightens the margin at each step. An operator whose reported methane stays flat will still see verified methane scaled up by whatever factor CDPHE publishes for that year.
The Operator-Specific Program Alternative
The rule gives all upstream operators subject to Section VIII two paths [1]. Take the division’s default factor, or run an operator-specific program built from the operator’s own measurements [1].
How does an operator-specific program work? Site-level direct measurements under a measurement strategy inform the methane it reports, considering how representative monitored sites are [2]. The operator’s measurement-informed inventory, audited by a certified third party for 2025, 2027 and 2030, then takes the place of the default factor’s adjustment [2].
The operator must notify CDPHE by September 30 of the prior year, for reporting years 2025 through 2030, and submit a measurement strategy summary [2]. For 2025 and 2026 the strategy must be one CDPHE developed, and CDPHE can require revisions to a program or deny it [2]. The measurement strategy must consider how representative the monitoring sites are, and its technology must capture a sufficient portion of expected emissions [2].
The incentive is straightforward. An operator whose facilities genuinely emit less than the default factor implies can report a lower measurement-informed inventory instead of a scaled one. If its measurement-informed methane comes in below the default-scaled figure, the operator’s intensity ratio improves against the annual target. For an operator sitting near a target threshold, that gap can decide compliance.
The tradeoff is cost and effort. Building out monitoring, gathering representative data, paying for certified third-party audits, and clearing CDPHE review all take real investment. They pay off when the reduction in verified emissions outweighs that spend.
If an operator-specific program for 2028 looks worthwhile (notice due September 30, 2027), this is the kind of work we do at TetraSoft.
TetraSoft MAES is the Mechanistic Air Emissions Simulator, developed at CSU and UT Austin, which we use through a partnership with Colorado State University. It models each facility’s equipment and reports probability distributions of expected emissions rather than a single value. With field measurement data, it builds a Measurement-Informed Inventory (MII) of routine and abnormal emissions; a formal program still needs Division-reviewed direct measurement. From there we can model the measurement-informed inventory your own data would support and weigh it against the CDPHE default.
The third post in this series walks through how to get a Colorado operator-specific verification factor, from eligibility to program design.
Frequently Asked Questions
Does the verification factor apply to all greenhouse gases or only methane?
The State Default Intensity Verification Factor under Regulation 7 Part B Section VIII applies to methane emissions reported through ONGAEIR [2]. The intensity itself sums greenhouse gas emissions from preproduction and production, expressed in mtCO2e, not methane alone [2]. CO2 and other greenhouse gases reported in ONGAEIR are not scaled by the verification factor, which is defined as a methane factor [2].
What happens if an operator exceeds the annual intensity target?
An operator whose verified GHG intensity exceeds the applicable annual target must achieve additional reductions in the following calendar year [2]. The extra reductions must address the difference between its reported intensity and the target [2]. The operator must also submit an updated plan by June 30 of the next year showing how it will meet the target and additional reductions [2].
Can an operator use its own factor without an approved monitoring program?
No [2]. The operator must notify CDPHE and submit a summary of its measurement strategy, and CDPHE may require revisions or deny the program [2]. An operator without an operator-specific program must apply the published State Default Intensity Verification Factor to its ONGAEIR methane [2].
Is the 1.164 factor permanent, or does it change each year?
CDPHE publishes new State Default Intensity Verification Factors by December 31 of each year through 2029, each valid for the following calendar year [2]. Each year’s factor is developed from monitoring data to account for the difference between monitored and reported methane [1]. The 1.164 value applied to the 2025 reporting year; the 2026 factors are 2.2 to 2.7 by region [1].
This post is for informational purposes only and does not constitute legal or compliance advice. Consult qualified legal counsel or a compliance professional for guidance specific to your operations and jurisdiction.
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References
- CDPHE, Oil and Gas Greenhouse Gas Intensity Program, cdphe.colorado.gov/oil-and-gas-greenhouse-gas-intensity-program (state default intensity verification factor publications and methodology). https://cdphe.colorado.gov/oil-and-gas-greenhouse-gas-intensity-program
- 5 CCR 1001-9, Colorado AQCC Regulation 7, Part B, Section VIII (Oil and Natural Gas Greenhouse Gas Intensity Program); codified via the Colorado Secretary of State and Cornell LII, law.cornell.edu/regulations/colorado/5-CCR-1001-9-B-VIII. https://www.law.cornell.edu/regulations/colorado/5-CCR-1001-9-B-VIII
- Colorado Secretary of State, Code of Colorado Regulations, 5 CCR 1001-9 (Regulation Number 7) rule history, coloradosos.gov/CCR. https://www.coloradosos.gov/CCR/DisplayRule.do?action=ruleinfo&ruleId=2341&deptID=16&agencyID=7&deptName=Department%20of%20Public%20Health%20and%20Environment&agencyName=Air%20Quality%20Control%20Commission&seriesNum=5%20CCR%201001-9
- AQCC Regulation 7, Part B, Section VIII rulemakings: December 2021 (upstream GHG intensity requirements), July 2023 (GHG intensity verification rule), and February 20, 2026 (small-operator timeline revision, effective April 14, 2026). https://www.coloradosos.gov/CCR/DisplayRule.do?action=ruleinfo&ruleId=2341&deptID=16&agencyID=7&deptName=Department%20of%20Public%20Health%20and%20Environment&agencyName=Air%20Quality%20Control%20Commission&seriesNum=5%20CCR%201001-9
- Colorado Senate Bill 19-181 (2019), Colorado General Assembly, leg.colorado.gov/bills/sb19-181. https://leg.colorado.gov/bills/sb19-181
- Alvarez et al., Assessment of methane emissions from the U.S. oil and gas supply chain, Science 361(6398):186-188, 2018, DOI:10.1126/science.aar7204. https://doi.org/10.1126/science.aar7204
- Sherwin, Rutherford, et al., US oil and gas system emissions from nearly one million aerial site measurements, Nature 627:328-334, 2024, DOI:10.1038/s41586-024-07117-5; Author Correction, 29 May 2026, DOI:10.1038/s41586-026-10605-5. https://doi.org/10.1038/s41586-024-07117-5
- Colorado Air Quality Control Commission, Regulation Number 7 rulemaking hearing of September 16-18, 2026 (hearing notice and final rule proposal), cdphe.colorado.gov/aqcc-upcoming-previous-commission-hearings. https://cdphe.colorado.gov/aqcc-upcoming-previous-commission-hearings
- CDPHE, ONGAEIR Program reporting guidance and deadlines, cdphe.colorado.gov/ongaeir. https://cdphe.colorado.gov/ongaeir
- METEC (Colorado State University) and CDPHE, Colorado Ongoing Basin Emissions (COBE) project, metec.colostate.edu/colorado-ongoing-basin-emissions-cobe. https://metec.colostate.edu/colorado-ongoing-basin-emissions-cobe
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