What Colorado's 1.164 Verification Factor Costs Operators

Colorado’s 2025 upstream oil and gas workbooks were due June 30, 2026, and their methane faces a state multiplier unless operators use an operator-specific program [1]. The scaled total helps decide whether an upstream operator meets its greenhouse gas intensity target, so it drives compliance plans and enforcement exposure [2]. For 2026 emissions the multiplier rises from 1.164 to between 2.2 and 2.7 by region, about 1.9 to 2.3 times as high [1]. Fees on co-emitted regulated pollutants such as VOCs are rising too, from $84 per ton for 2025 emissions to $164 per ton from 2026 [3].

Colorado’s air regulator is CDPHE, the Colorado Department of Public Health and Environment, acting through its Air Pollution Control Division [1]. The State Default Intensity Verification Factor is a multiplier CDPHE publishes yearly through 2029 to account for differences between monitored and reported upstream methane [1]. It applies to the upstream methane operators file in ONGAEIR, Colorado’s yearly oil and gas emissions inventory [1]. ONGAEIR is Oil and Natural Gas Annual Emission Inventory Reporting, and the factor adds no direct charge of its own [4].

Fees come from AQCC Regulation 3, and the AQCC (Air Quality Control Commission) is the body that adopts Colorado’s air rules [5]. Methane does not pay the per-ton fee charged on VOCs (volatile organic compounds, hydrocarbon vapours that form ozone) [3]. VOCs are reported on an APEN (Air Pollutant Emission Notice), the emissions filing on which each source’s annual fee is based [6]. From 2027, ONGAEIR reporters file an Emissions Reporting Notice, a type of APEN, at $270 per emissions point for equipment above APEN thresholds [3].

This post is for Colorado upstream compliance and finance teams with no background in the rule. It shows how the multiplier becomes a fee estimate and an intensity-target risk, what other factor values cost, and what changed since 2025. Three costs excluded from the figures and common questions come last; how the Colorado Reg 7 verification factor works is explained in our earlier post.

Quick Answer: At the 2025 factor of 1.164, each 1,000 reported metric tons of upstream CH₄ gains 164 verified tons, CDPHE’s adjustment for monitored-versus-reported differences [1]. The 164 tons imply about 49.2 tons of VOC, at an assumed 0.3 tons of co-emitted VOC per ton of CH₄. At Regulation 3’s $84-per-ton fee for 2025 emissions, 49.2 tons of VOC would cost about $4,130, only hypothetically: the factor scales methane, not APEN VOC [6]. The harder-to-price cost is compliance: a multiplier-driven miss requires extra reductions the next year and an updated intensity plan, both enforceable by CDPHE [2].

How the Multiplier Converts Reported Tons Into Dollar Exposure

The multiplier reaches operators’ budgets through intensity-target risk; the VOC fee estimate prices a hypothetical VOC gap, not a charge the factor creates.

An Illustrative Regulation 3 Fee Calculation: Roughly $4,130 Per Year

At the $84-per-ton 2025 rate, a hypothetical 1,000-metric-ton CH₄ operator would pay about $4,130 if co-emitted VOC rose with the factor at 0.3. That figure prices 49.2 tons of VOC, the assumed 0.3 ratio applied to the 164 metric tons of methane the factor adds. AQCC Regulation 3 sets Colorado’s annual emission fees on regulated air pollutants, including VOCs, and on hazardous air pollutants (HAPs) reported on APENs [3]. VOCs and HAPs from sources required to file an APEN are subject to Regulation 3 annual emission fees [5].

The verification factor adjusts a different number: the verified methane total used by the Regulation 7 intensity program [4]. Nothing in the factor’s terms changes the VOC tonnage an operator reports on its APENs [4].

So this section’s calculation is a hypothetical, not a charge the multiplier creates. It answers a narrower question. If the same measurement gap the factor represents also applied to co-emitted VOCs, what would that gap cost at current fee rates? On the rule text, the multiplier alone does not create this charge, because it applies to ONGAEIR methane, not APEN VOC totals.

Regulation 3 counts VOCs as a regulated air pollutant, and every source that must file an APEN pays an annual fee on them [3]. The fee is $84 per ton for 2025 emissions and $164 per ton for emissions after 2025 [3].

Consider a hypothetical operator that reports 1,000 metric tons of CH₄ for 2025. We assume 0.3 tons of co-emitted VOC per ton of CH₄, a round figure no source gives; ratios vary widely by gas composition and equipment. The calculation then runs in four steps:

1. Verified methane is 1,000 × 1.164 = 1,164 tons, so the multiplier adds 164 tons.
2. The implied VOC is 164 × 0.3 = 49.2 tons.
3. At the 2025 rate, 49.2 × $84 = $4,132.80, about $4,130 a year.
4. The same tons at the post-2025 rate cost 49.2 × $164 = $8,068.80, about $8,070 a year.

Regulation 3 uses short tons elsewhere (14 megagrams = 15 tons), so fee figures computed here on metric tons likely run about 10% low.

The Greenhouse Gas Fee Pool Does Not Scale With the Factor

For default-factor operators, the factor does not change the greenhouse gas fee, which bills on CO2e reported under Section V, before the factor. Methane itself falls under a separate greenhouse gas fee [3]. It applies to an ONGAEIR reporter whose company-wide emissions reach 25,000 metric tons of CO2e a year [3]. CO2e, carbon dioxide equivalent, weights each gas by its warming effect relative to CO2; Regulation 7 uses 100-year global warming potentials from IPCC AR5 [2].

The greenhouse gas fee has no fixed per-ton rate [3]. CDPHE splits a fixed total of $6,540,000 among fee payers by the CO2e each one reported, rising to $7,250,000 from 2027 [3]. Each bill uses emissions from two years earlier, so a 2024 bill covered 2022 emissions as reported in 2023 [3].

Worked through, the rule’s six-step formula reduces to the fixed total multiplied by the operator’s share of all CO2e reported by fee payers. The formula bills on CO2e reported under Regulation 7, Part B, Section V (ONGAEIR); the division applies the default factor to upstream methane after submission. Operators near 25,000 metric tons of CO2e can confirm with CDPHE that the reported total, without the factor, sets the fee.

The Multiplier Can Push Operators Past Intensity Targets

For operators near an intensity target, the intensity program itself may be the larger financial consideration. Colorado’s greenhouse gas intensity program under AQCC Regulation 7, Part B, requires upstream operators to meet declining intensity targets set for 2025, 2027 and 2030 [2]. Targets are in metric tons of CO2e per thousand barrels of oil equivalent, with methane scaled by the multiplier unless an operator-specific program applies [2].

An April 2026 revision to Regulation 7 (adopted February 20, 2026, effective April 14, 2026) dropped the 2025 intensity target for small operators [1]. They also have no 2027 target if they stay small in 2026 and 2027, so their first company-wide target can be 2030 [2]. Small means under 45 kBOE of production in 2025, thousands of barrels of oil equivalent, a unit that counts hydrocarbon liquids and natural gas together [2]. Larger upstream operators keep the 2025 and 2027 targets, and must hold each prior target in 2026, 2028 and 2029 [2].

For operators using the default factor, the intensity calculation scales reported ONGAEIR methane, not the other greenhouse gases [2]. An operator whose reported intensity would meet the applicable target can exceed it after the multiplier is applied. Operators can instead use an operator-specific program built on site-level direct measurement, whose result may be higher or lower.

Missing an intensity target triggers no automatic per-ton penalty, but the operator must make extra reductions the next year and update its intensity plan [2]. After notice and a conference, if CDPHE finds a violation, it must order compliance [7]. That order may assess civil penalties, require projects to mitigate excess emissions, alter or revoke permits, or require a noncompliance penalty calculation [7]. The statute set the cap at $47,357 per day of violation; with the AQCC’s annual inflation adjustments it is $57,773 from January 1, 2026 [8].

As of November 2026 we found no published CDPHE penalty for a missed intensity target; first company-wide target-year reports were due June 30, 2026. The absence of a published case does not mean the risk is zero. It means the risk has a per-day statutory cap but no precedent from which to price it.

Sensitivity Analysis: What Different Multiplier Values Cost Per 1,000 Reported Tons

If 2026 factors of 2.2 to 2.7 scale all reported methane, the hypothetical costs $59,040 to $83,640 at $164 per ton; CDPHE guidance is pending. That is roughly 14 to 20 times the 2025 figure: added tons rise 7.3 to 10.4 times, and the rate 1.95 times. The 1.164 factor is CDPHE’s published 2025 value; the rule has CDPHE publish factors each year through 2029 [1]. The table gives seven multiplier scenarios, all based on 1,000 reported metric tons of CH₄.

Multiplier	Verified CH₄ (t)	Added CH₄ (t)	Implied VOC at 0.3 (t)	Fee at $84/ton, 2025 emissions	Fee at $164/ton, emissions after 2025
1.05	1,050	50	15	~$1,260	~$2,460
1.10	1,100	100	30	~$2,520	~$4,920
1.164 (2025)	1,164	164	49.2	~$4,130	~$8,070
1.20	1,200	200	60	~$5,040	~$9,840
2.2 (2026, Front Range)	2,200	1,200	360	~$30,240	~$59,040
2.5 (2026, rest of state)	2,500	1,500	450	~$37,800	~$73,800
2.7 (2026, West Slope)	2,700	1,700	510	~$42,840	~$83,640

Each row multiplies 1,000 t CH₄ by the factor, takes the added tons times the assumed 0.3 ratio, then multiplies by each fee rate. The 2026 factors apply to 2026 emissions, which Regulation 3 bills at $164 per ton, so that column matches their year [1].

The chart plots both fee rates across the factor range and marks each factor at the rate that applies to it. Pending CDPHE guidance, 2026 factors applied to all methane give $59,040 to $83,640 at $164 per ton, or $30,240 to $42,840 at $84.

For operators near an intensity threshold, the difference between 1.10 and 1.164 is not the $1,610 a year separating those rows at $84. It can decide whether the operator passes or fails. Stay current on ONGAEIR deadlines and those of the GHGRP, EPA’s yearly Greenhouse Gas Reporting Program for large emitters: subscribe for compliance updates and regulatory news [9].

What Has Changed Since the 2025 Factor

In 2026 the AQCC adopted three Regulation 7 revisions, and fee rates and factors rose.

Date	Action	What changes
By Jan 10, 2026 (due Dec 31, 2025)	CDPHE publishes 2026 default factors	2.2 (9-County Front Range), 2.7 (3-County West Slope), 2.5 (rest of state), for 2026 emissions due June 30, 2027 [1]
Feb 20, 2026 (effective Apr 14, 2026)	AQCC revises Regulation 7	Operators under 45 kBOE have no 2025 target, nor a 2027 target if still small; their first company-wide target can be 2030 [2]
2025 and 2026 emission years	New Regulation 3 fee rates apply	Regulated pollutants, including VOCs: $84/ton for 2025 emissions, $164/ton after 2025; HAPs: $557/ton, then $1,090/ton [3]
May 22, 2026 (effective Jul 15, 2026)	AQCC revises Regulation 7 again	Current version on the Secretary of State register [10]
Sep 18, 2026 (effective Nov 14, 2026)	AQCC adopts a third revision	Completes alignment with EPA’s 2024 existing-source methane guidelines (Subpart OOOOc); takes effect November 14, 2026 [11].

Three Cost Categories Excluded From This Analysis

Staff costs, monitoring investment, and ESG disclosure impact are excluded from this post’s fee figures because they vary too widely across operators to model generically. ESG stands for environmental, social and governance, the sustainability reporting that investors and customers read. Each category is real. Staff and monitoring costs do not scale with the multiplier in a simple way.

Staff Time and Monitoring Add Costs the Model Omits

Staff time and monitoring are costs this post’s fee model omits. The division applies the default factor to upstream methane after ONGAEIR submission, but operators spend staff time validating data and checking its intensity effect. Some operators may weigh an operator-specific program as the alternative to the default multiplier. For them, program design, measurement procurement and, from 2027, Division approval of any operator-developed strategy add costs the sensitivity table does not capture.

Upstream operators choosing an operator-specific program over the default factor must fund site-level direct measurement and certified third-party audits. Those costs vary widely by operator size, facility count, and chosen measurement technology.

Higher Verified Totals Flow Into Public ESG Disclosures

Where an operator on the default factor discloses its verified Colorado methane, that figure is reported methane times the factor, so higher. Such disclosures can include investor ESG reports and supply-chain methane certifications; OGMP 2.0 (the Oil & Gas Methane Partnership) instead uses members’ measurement-based methods. OGMP 2.0, the Oil & Gas Methane Partnership, is a methane measurement and reporting initiative led by the UN Environment Programme [12].

The reputational cost of a 16.4% upward adjustment to verified methane is not quantifiable in a generic model. Operators with public methane intensity commitments may face questions about the gap between reported and verified figures. Operators preparing OGMP 2.0 or investor disclosures should confirm which Colorado figure, if any, their framework accepts; OGMP 2.0 expects measurement-based reporting. They should document the basis for whichever figure they file.

Operators seeking to benchmark their reported tonnage against peers can explore the TetraSoft Atlas Dashboard, our subscription platform, for facility-level Colorado emissions data [13].

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.

Frequently Asked Questions

Does the state default intensity verification factor apply to all ONGAEIR emission categories?

The State Default Intensity Verification Factor applies to upstream ONGAEIR methane under Regulation 7, Part B, unless the operator uses an operator-specific program [4]. The multiplier applies to upstream ONGAEIR methane, not other pollutants; it feeds company-wide and new-facility intensity in plans and annual verifications [4]. Operators should check CDPHE’s guidance on how the 2026 factor applies to reported emissions, which CDPHE says it will issue before June 30, 2027.

Can an operator replace the state default verification factor without continuous monitoring?

The operator-specific program under Regulation 7, Part B does not require continuous monitoring exclusively, but it must include site-level direct measurement [4]. For 2025 and 2026 the strategy must be one the Division developed; from 2027 operators may submit their own for approval [2]. Operators evaluating an operator-specific program should review the Division’s strategies in the Intensity Verification Protocol and, from 2027, the approval process in VIII.F.3.b.

Has CDPHE published data on the distribution of reported methane tonnage across Colorado upstream operators?

CDPHE’s ONGAEIR dashboard publishes facility-level emissions data, but we found no single CDPHE summary table of operator-level methane tonnage. TetraSoft Atlas, our subscription platform, holds 124,607 Colorado wells by distinct API-10 number, linking each to ONGAEIR reports where a match exists [13]. Its Colorado emissions view ranks operators by reported methane for 2021 to 2024 and drills down to individual sites [13].

Stay ahead of ONGAEIR deadlines and regulatory changes: sign up for the TetraSoft newsletter.

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References

1. Colorado Department of Public Health and Environment, Air Pollution Control Division, Oil and gas greenhouse gas intensity program: 2025 ONGAEIR workbooks due June 30, 2026 subject to the 2025 state default intensity verification factor of 1.164; 2026 factors of 2.2 (9-County Front Range), 2.7 (3-County West Slope) and 2.5 (Rest-of-State) for reporting year 2026 emissions due June 30, 2027. https://cdphe.colorado.gov/apcd-ghg-intensity-program. Accessed November 2026.
2. Colorado Air Quality Control Commission, Regulation Number 7 (5 CCR 1001-9), Part B, Section VIII (version effective July 15, 2026): Greenhouse Gas Intensity Program for Oil and Natural Gas Upstream Segment. https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=12621&fileName=5%20CCR%201001-9.
3. Colorado Air Quality Control Commission, Regulation Number 3 (5 CCR 1001-5), Part A, Sections VI.C and VI.D (version effective July 15, 2026): annual emission fees and the greenhouse gas emission fee. https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=12619&fileName=5%20CCR%201001-5.
4. Colorado Air Quality Control Commission, Regulation 7 (5 CCR 1001-9), Part B, Section VIII.F: Greenhouse Gas Intensity Verification (State Default Intensity Verification Factor, Section VIII.F.3.a). Colorado Department of Public Health and Environment.
5. Colorado Air Quality Control Commission, Regulation 3 (5 CCR 1001-5): Stationary Source Permitting and Air Pollutant Emission Notice Requirements. Fee schedule provisions.
6. Colorado Department of Public Health and Environment, Air Pollution Control Division, Emissions and permitting fees: annual fee based on emissions on the most current APEN; $84 per ton of criteria pollutant for calendar year 2025 emissions and $164 per ton for calendar year 2026 emissions and later. https://cdphe.colorado.gov/apcd/emissions-and-permitting-fees. Accessed November 2026.
7. Colorado Revised Statutes § 25-7-115: Enforcement; civil actions; definitions. https://colorado.public.law/statutes/crs_25-7-115.
8. Colorado Air Quality Control Commission, Common Provisions Regulation (5 CCR 1001-2), Section III, Table 1: maximum civil penalty adjusted for inflation, $57,773 per day effective January 1, 2026. https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=12286&fileName=5%20CCR%201001-2.
9. U.S. Environmental Protection Agency, Greenhouse Gas Reporting Program (GHGRP): annual emissions data from about 8,000 large emitters, suppliers and CO₂ injection sites. https://www.epa.gov/ghgreporting. Accessed November 2026.
10. Colorado Secretary of State, Code of Colorado Regulations, 5 CCR 1001-9 (Regulation Number 7) version list: current version effective July 15, 2026 (adopted May 22, 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.
11. Colorado Department of Public Health and Environment, Air Quality Control Commission regulations: Regulation Number 7 (5 CCR 1001-9) listed as adopted 09/18/26, effective 11/14/26. https://cdphe.colorado.gov/aqcc-regulations. Accessed November 2026.
12. UN Environment Programme, Oil & Gas Methane Partnership 2.0 (OGMP 2.0): methane measurement and reporting initiative for the oil and gas sector. https://www.ogmpartnership.org/. Accessed November 2026.
13. TetraSoft Atlas, Colorado well count (124,607 wells by distinct API-10, counted October 27, 2026) and Colorado emissions analytics. Internal data asset.
14. Colorado Revised Statutes § 25-7-122: Civil penalties; rules; definitions. https://colorado.public.law/statutes/crs_25-7-122.