Colorado Reg 7 GHG Intensity: How the Verification Factor Works

Colorado’s Oil and Gas Greenhouse Gas Intensity Program scales ONGAEIR-reported methane emissions by a state-published verification factor before comparing them against annual intensity targets. [1] The division applies the state default factor to reported and validated methane emissions after submission, for operators not implementing an operator-specific program. [2] The factor for the 2025 reporting year is 1.164, meaning the state assumes reported inventories undercount actual methane by roughly 16.4%. [3] The program, codified in Regulation 7 Part B Section VIII, exists because peer-reviewed measurement studies have consistently shown that factor-based inventories underestimate actual methane from oil and gas operations. [1] For compliance managers filing ONGAEIR each year, the verification factor is not optional background. It determines whether your operations meet Colorado’s declining intensity targets through 2030. This post is the first in a three-part series covering the program mechanics and the cost implications of the default factor. A third post will cover how operator-specific monitoring programs can change that number.

What Is the Reg 7 Part B Section VIII GHG Intensity Program?

Colorado’s GHG Intensity Program sets declining annual methane-intensity targets for upstream oil and gas operations statewide. [1] The Air Quality Control Commission (AQCC) adopted the first greenhouse gas intensity requirements for upstream oil and gas in December 2021, under authority that traces to Senate Bill 19-181, enacted in 2019. [4] The intensity verification framework, including the state default verification factor, was adopted in July 2023. [5]

Why Colorado Built It

The program exists to close a well-documented gap between what operators report in bottom-up inventories and what top-down measurement studies detect. [3] The gap is not small. A landmark EDF-led synthesis found US oil and gas supply-chain methane roughly 60% above the EPA inventory estimate, with the production segment about twice the inventory figure (Alvarez et al., 2018). [6] That finding still surprises operators who trust their bottom-up numbers, but subsequent large-scale campaigns report comparable gaps. [7] Colorado built a regulatory structure that adjusts reported emissions upward using a verified multiplier derived from measurement data. The adjusted total is then compared to a declining intensity benchmark.

Who Must Comply

The program applies to upstream oil and gas operators in Colorado that report through ONGAEIR. [1] No opt-in is required. [1] Midstream and downstream facilities fall outside the program’s scope. [1] Operators subject to ONGAEIR reporting thresholds are automatically subject to the intensity program; there is no separate enrollment step. [3]

How the Verification Factor Produces the Intensity Ratio

The intensity calculation follows a three-step flow: operators submit reported methane through ONGAEIR, the state-published factor scales that methane upward, and the result feeds a ratio compared against the annual target. [1]

Step 1: Reported Methane via ONGAEIR

Operators calculate and submit facility-level methane emissions through the annual ONGAEIR process. [2] These reported totals use standard emission estimation methodologies (emission factors, engineering calculations, or direct measurement where applicable). [2] 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. [2]

Step 2: Multiply by the State Default Intensity Verification Factor

CDPHE publishes a State Default Intensity Verification Factor by December 31 each year, applicable to the following reporting year, with publications running through December 31, 2029. [3] The factor is derived from the ratio of measurement-based (top-down) methane estimates to bottom-up reported inventories for Colorado oil and gas operations. [3] The 2025 first-year factor of 1.164 was set from the measurement-to-inventory analysis available when it was published in December 2024. [3] The Colorado Ongoing Basin Emissions (COBE) study, a joint CDPHE and CSU/METEC field campaign whose final report was released in 2025, informs the 2026 factor rather than the 2025 value. [8] The COBE-informed 2026 factors are basin-specific rather than a single statewide number, and press coverage of the COBE results reports them as substantially larger than the 2025 value (on the order of 2.2 to 2.7 times reported inventory, by basin).

The verified 2025 reporting year factor is 1.164. [3] The factor for the 2026 reporting year was required to be published by December 31, 2025. [1] CDPHE has since published the 2026 factors. Unlike the single statewide 1.164 that applied for the 2025 reporting year, the 2026 factors are basin-specific and substantially larger, reflecting the Colorado Ongoing Basin Emissions (COBE) measurement campaign. The worked examples below use the 2025 statewide factor of 1.164 as a clean single-number illustration of the mechanic; operators apply the published factor for their basin and current reporting year. Operators are not locked into that published default. [1] An approved operator-specific program lets them substitute a factor derived from their own measurements, a path covered later in this post. [1]

An operator reporting 500 metric tons of methane in ONGAEIR would calculate verified methane as 500 multiplied by 1.164, yielding 582 metric tons. [1] That 582-ton figure, not the original 500, enters the intensity ratio. A 16.4% adjustment may sound modest, but for a large operator reporting thousands of metric tons, the absolute tonnage increase can shift the intensity ratio from compliant to non-compliant.

Step 3: Intensity Ratio vs. Annual Target

The GHG intensity ratio divides verified methane emissions by oil and gas production, expressed in units appropriate to the program’s metric. [1] CDPHE compares each operator’s intensity ratio against the applicable annual target. [1] Operators whose verified intensity exceeds the target face compliance obligations under the program, including potential requirements to develop and implement emission reduction plans. [1]

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?

The intensity targets decline annually through 2030, operators can pursue a lower factor through an approved monitoring program, and the verification factor should not be confused with the Unit Impact Multiplier (UIM). [9]

The Intensity Target Schedule Through 2030

Regulation 7 Part B Section VIII sets a schedule of intensity targets that tightens through 2030. [1] The regulation names explicit targets for 2025, 2027, and 2030, and holds the years in between at the previous target. [1]

The targets split operators into two classes by size. [1] A majority operator reported at least 10,000 kBOE of Colorado production in 2022, and a minority operator reported less. [1] Each class carries its own target, measured in metric tons of CO2e per thousand barrels of oil equivalent (mtCO2e/kBOE). [1]

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)

Across the schedule, the majority-operator target falls from 10.94 to 6.80 mtCO2e/kBOE, and the minority-operator target from 34.39 to 21.38. [1] Both are reductions of roughly 38% from the 2025 starting point. [1]

A February 2026 rulemaking changed the timeline for the smallest operators. [5] An operator producing less than 45 kBOE in a calendar year now faces a single compliance deadline in 2030. [5] That threshold works out to roughly 123 barrels of oil per day or 715 thousand cubic feet of gas per day. [5] It replaces the stepped 2025 through 2029 targets that applied to those operators before, and operators above 45 kBOE stay on the original schedule. [5]

The extra time changes the deadline, not the destination. Every operator under 45 kBOE sits below the 10,000 kBOE majority threshold, so its 2030 target is the minority value of 21.38 mtCO2e/kBOE. Meeting the strictest year in one step can demand a larger cut over a shorter runway than the phased schedule would have.

As the intensity target declines each year, the verification factor’s upward scaling of reported methane makes meeting that target harder. An operator whose reported inventory stays flat year over year will see verified methane remain elevated by the factor. Meanwhile, the target that operator must meet drops.

The Operator-Specific Program Alternative

Operators are not required to use the state default factor. [1] The rule gives every upstream operator two paths. Take the division’s default factor, or run an approved operator-specific program built from the operator’s own measurements. [3]

So how does an operator arrive at its own number? It measures methane across a representative sample of its own facilities, then compares those measurements against what it reported in ONGAEIR. [1] The resulting ratio of measured to reported becomes the operator’s proposed verification factor, standing in for the statewide default.

That number is not self-certified. The operator submits a monitoring plan, and CDPHE reviews and approves the program under its intensity verification protocol before any operator-specific factor takes effect. [3] The plan has to show that the monitoring data represents the operator’s full facility population, not just its cleanest sites.

The incentive is straightforward. An operator whose facilities genuinely emit less than the statewide average can earn a lower factor. That lower factor scales reported methane up by less than the default would, improving the operator’s intensity ratio 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, and clearing CDPHE approval all take real investment. They pay off only when the reporting reduction outweighs that spend.

If the operator-specific path looks worth exploring, this is the kind of work we do at TetraSoft. Our MAES platform turns field measurement data into a Measurement-Informed Inventory. From there we can model the factor your own data would support and weigh it against the CDPHE default.

The third post in this series walks through the eligibility requirements, the approval process, and monitoring program design.

What This Factor Is Not: Distinguishing It From the UIM

The State Default Intensity Verification Factor is sometimes confused in industry conversation with the Unit Impact Multiplier (UIM), a separate CDPHE tool. The UIM is used in air quality permit application dispersion modeling to account for cumulative impacts in specific geographic areas. [9] The verification factor under Regulation 7 Part B Section VIII adjusts reported methane inventories for the GHG intensity program. [1] The two numbers serve different regulatory purposes and are derived from different methodologies. The UIM applies at the permitting stage; the verification factor applies at the annual intensity compliance stage. [3]

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. [1] The GHG intensity program targets methane specifically as the primary greenhouse gas from upstream oil and gas operations in Colorado. [1] CO2 and other greenhouse gases reported in ONGAEIR are not subject to the same verification factor multiplier under this program. [1]

What happens if an operator exceeds the annual intensity target?

Operators whose verified GHG intensity exceeds the applicable annual target must develop and implement emission reduction measures as specified in Regulation 7 Part B Section VIII. [1] The regulation includes provisions for compliance timelines and corrective action. [1] Specific enforcement consequences depend on the degree and duration of exceedance and on CDPHE’s exercise of its enforcement authority.

Can an operator use its own factor without an approved monitoring program?

No. [1] The regulation requires CDPHE approval of an operator-specific monitoring program before an alternative factor can replace the state default. [1] Operators who have not obtained approval must use the published State Default Intensity Verification Factor for their intensity calculations. [1]

Is the 1.164 factor permanent, or does it change each year?

CDPHE publishes a new State Default Intensity Verification Factor by December 31 each year, applicable to the following reporting year. [1] The factor is recalculated annually based on updated measurement-to-inventory ratio data. [3] The publication schedule runs through December 31, 2029, with each publication valid for the following reporting year. [3] The 1.164 value applies specifically to the 2025 reporting year and should not be assumed to remain constant for future years. [3]

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

1. 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.
2. CDPHE, ONGAEIR Program reporting guidance and deadlines, cdphe.colorado.gov/ongaeir.
3. 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).
4. Colorado Senate Bill 19-181 (2019), Colorado General Assembly, leg.colorado.gov/bills/sb19-181.
5. 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).
6. 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.
7. 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.
8. METEC (Colorado State University) and CDPHE, Colorado Ongoing Basin Emissions (COBE) project, metec.colostate.edu/colorado-ongoing-basin-emissions-cobe.
9. CDPHE, Air Permitting Program, Unit Impact Multiplier (UIM) guidance.