If you operate oil and gas facilities in Colorado, Regulation Number 7 is the state air rule written for your sector, alongside other Commission rules [1]. It reaches leak inspections, pneumatic equipment, the annual emissions inventory and a greenhouse gas intensity target that forces further reductions when it is missed [1]. Part B Section I applies in northern Weld County and the 8-Hour Ozone Control Area, the Denver-area zone failing the federal ozone standard [1].
References written before mid-2023 describe a different regulation [1]. The oil and gas requirements sit in Part B, moved there from Part D and, for Sections VII and VIII, from Regulation Number 22 [1].
This post first covers what Regulation 7 covers now and which Part B rules reach your facilities. It ends with the Colorado Ongoing Basin Emissions (COBE) study, the measurement-informed inventory route out, and what changed this year. COBE is the least settled part of the picture: its two models disagree, and a second phase, COBE-2, is reconciling them [2].
Quick Answer: Colorado Regulation Number 7, 5 CCR 1001-9, is titled Control of Emissions from Oil and Gas Emissions Operations [1]. Part B Section I applies in the 8-Hour Ozone Control Area and northern Weld County; Sections II through VIII apply statewide, except Section VI.E [1]. Section VIII.F.3 requires intensity operators to develop a measurement-informed inventory, by the state default factor or an operator-specific program [1]. The version in force until November 14, 2026 took effect July 15, 2026 [3]. A revision adopted September 18, 2026 takes effect November 14, 2026 [4].
On this page
- What Colorado Regulation 7 Covers Now
- Which Part B Rules Reach Your Facilities
- Section V Is the Filing Everything Else Is Computed From
- Section VIII Is Where Regulation 7 Costs Money
- What the COBE Study Found About the Multiplier
- The Way Out Is a Measurement-Informed Inventory
- What Changed in Regulation 7 This Year
What Colorado Regulation 7 Covers Now
Regulation 7 is organised into three parts, and Part B carries the oil and gas operating requirements [1]. Part A sets applicability and definitions and carries Appendix A, the ozone nonattainment and attainment maintenance area maps [1]. Part C holds the statements of basis and statutory authority [1].
| Part B section | Subject | Where it applies |
|---|---|---|
| I | Volatile organic compound emissions from oil and gas operations | 8-Hour Ozone Control Area and northern Weld County (State Only: any other ozone nonattainment area) |
| II | (State Only) Statewide controls for oil and gas operations | Statewide |
| III | (State Only) Natural gas-actuated pneumatic controllers and pumps | Statewide |
| IV | (State Only) Natural gas transmission and storage segment | Statewide |
| V | (State Only) Oil and natural gas operations emissions inventory | Statewide |
| VI | (State Only) Pre-production, early-production and production operations | Statewide, except VI.E (8-Hour Ozone Control Area and northern Weld County) |
| VII | (State Only) Midstream segment fuel combustion equipment | Statewide |
| VIII | (State Only) Greenhouse gas intensity program, upstream segment | Statewide |
Section titles shortened from 5 CCR 1001-9, version effective July 15, 2026; applicability from Part A, Section I.A.1. [1]
Regulation 7’s three parts, and which of Part B’s eight sections reach the whole state. Built from 5 CCR 1001-9, version effective July 15, 2026.
The State Only marking is not cosmetic. Part A states that Sections II through VIII, and any other section marked State Only, are not federally enforceable unless otherwise identified [1].
Section I is the part written into Colorado’s ozone state implementation plan for the nonattainment area [1]. EPA’s approved plan holds the pre-2023 Part D Section I, state-effective January 30, 2022, with State Only provisions excluded [5]. It also holds selected provisions of the old Part D Sections II and III [5]. Those approved provisions are what EPA can enforce until it approves the renumbered Part B text.
Part D Is Gone, and Most Citations Still Point There
Through the version effective February 14, 2023, Regulation 7 was a different document [3]. It was titled Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions [3]. It ran to Parts A through F and put the oil and gas requirements in Part D [3]. The version effective June 14, 2023 retitled it and collapsed it to Parts A, B and C [3].
Section numbering survived the move, which is what makes the stale citations easy to miss. Part D Section I and Part B Section I are both titled Volatile Organic Compound Emissions from Oil and Gas Operations [1]. A memo citing Part D Section I.L. points at real requirements under a letter the regulation no longer uses.
Which Part B Rules Reach Your Facilities
For Section I, applicability turns on two tests: where the operation sits and what it handles [1]. Part B Section I applies to oil and gas operations that collect, store or handle hydrocarbon liquids or produced water [1]. Those operations must sit in the 8-Hour Ozone Control Area, at or upstream of a natural gas plant [1]. Since February 14, 2023 the section also reaches those operations in northern Weld County [1].
Regulation 7 drew the 8-Hour Ozone Control Area under earlier federal ozone standards, before the 2015 one [1]. EPA set the current ground-level ozone standard at 70 parts per billion in 2015; the 2008 standard remains in effect for designated areas [6].
An area fails it on a three-year record rather than a bad afternoon [6]. EPA averages each year’s fourth-highest daily maximum eight-hour reading over three years; an area whose figure exceeds 70 ppb fails the standard [6]. Regulation 7 names the area’s members: Adams, Arapahoe, Boulder, Douglas and Jefferson counties, Denver and Broomfield, and defined portions of Larimer and Weld [1]. Together with northern Weld County, it decides where Part B Section I applies [1].
That geography holds about a third of Colorado’s producing wells [7]. Of roughly 124,500 well records at the Energy and Carbon Management Commission (ECMC), about 54,500 sit in that area, about half plugged and abandoned [7]. Weld County alone holds about 45,900 of them, and Weld is covered end to end [7].
Where Part B Section I reaches. Boundary from 5 CCR 1001-9 Part A, Section II.A.1 and II.A.3; the regulation’s own maps are at Part A, Appendix A, Section II. [1]
How Often Regulation 7 Makes You Look for Leaks
Section I.L. sets leak detection and repair frequency by facility type and emissions [1]. Natural gas compressor stations inspect at least quarterly using an approved instrument monitoring method [1]. Section I.B.3 defines that term as an infra-red camera, EPA Method 21, or another instrument-based method the Division approves under Section I.L.8 [1].
The infra-red camera in that definition is an optical gas imaging (OGI) camera. Section I.L. sets a floor: well production facilities with 1 to 6 tons per year of uncontrolled actual VOC emissions inspect at least annually [1]. Above 6 tons per year, they inspect at least semi-annually [1]. The statewide Section II.E, which also applies in the ozone area, is stricter [1].
From January 1, 2023, pre-May 2022 facilities at 2 to 50 tons per year inspect quarterly, more often near occupied areas or impacted communities [1]. Facilities that began operating on or after May 1, 2022 inspect at least monthly [1].
Where storage tanks are present, the tier is set by the highest emitting single tank rather than the facility total [1]. Where no oil or condensate storage tanks are present, the facility’s controlled actual VOC emissions from all permanent equipment govern instead [1]. Centralized oil stabilization facilities inspect quarterly from April 1, 2023, and transmission and storage compressor stations from May 1, 2026 [1].
Section V Is the Filing Everything Else Is Computed From
Section V supplies the reported emissions the intensity program starts from: the annual Oil and Natural Gas Annual Emission Inventory Report, known as ONGAEIR [1].
The report is due from operators statewide at or upstream of a natural gas processing plant [1]. The verification factor is applied to the methane figure that filing carries, and the intensity ratio is computed from the result [1]. Errors there flow into the ratio.
The filing itself is covered in Colorado ONGAEIR Due June 30: A Practical Filing Checklist.
Section VIII Is Where Regulation 7 Costs Money
Section VIII is the greenhouse gas intensity program [1]. Like the NOx intensity targets in Section VI.E, it sets intensity targets, company-wide and for new well production facilities, rather than equipment standards [1]. The target is in metric tons of CO2 equivalent per thousand barrels of oil equivalent [1].
Section VIII.A defines an intensity operator as one that operates upstream segment activities or equipment [1]. A midstream or transmission company with no upstream activities or equipment is not an intensity operator, so Section VIII’s duties do not reach it.
The target depends on how much you produce [1]. Section VIII sets its own two classes, and they are not the ones Section VI uses for NOx [1].
One route to majority status is an intensity operator’s company-wide Colorado production of 10,000 kBOE or more in calendar year 2022 [1]. A minority operator is one whose 2022 Colorado production was below that line, or a new entrant that bought a minority operator’s assets [1]. A minority operator that later crosses Section VIII.B.6’s production thresholds becomes a majority operator [1]. Separate rules cover operators new to the Colorado market [1].
For calendar year 2025 the targets were 10.94 mtCO2e/kBOE for a majority operator and 34.39 for a minority operator [1]. Operators producing less than 45 kBOE that year had no intensity target [1].
The number you are judged on is not the number you reported [1].
Section VIII.F.3 requires intensity operators to comply with “either Section VIII.F.3.a or Section VIII.F.3.b to develop a measurement-informed inventory used to demonstrate compliance” [1].
Route (a) is the state default intensity verification factor [1]. The Division publishes one or more such factors by December 31 each year through 2029, valid for the following calendar year [1].
Intensity operators “must apply a state default intensity verification factor to their ONGAEIR methane emissions… unless the operator elects to use an operator-specific program” [1].
For the 2025 reporting year the Colorado Department of Public Health and Environment (CDPHE) upstream intensity multiplier was 1.164, a single statewide figure [8]. An operator reporting 500 metric tons of upstream methane was judged on 582 [9].
TetraSoft cofounder Arthur Santos, this post’s author, first-authored a 2025 peer-reviewed study using a measurement-informed inventory to assess Denver-Julesburg Basin emissions [10]. It derived a MAES multiplier of 1.16 for the Denver-Julesburg Basin [10]. He is also a co-author of the COBE report discussed below [2]. How the factor is applied and what it costs are covered in Colorado Regulation 7: GHG Intensity Verification Factor and What Colorado’s 1.164 Verification Factor Costs Operators.
What the COBE Study Found About the Multiplier
The 2026 factors do not come from 1.164 [2]. They draw on the Colorado Ongoing Basin Emissions project, which CDPHE and Colorado State University jointly developed to help inform the 2026 verification rule [2]. COBE flew anonymous aerial campaigns over upstream facilities statewide, built measurement-informed inventories from the results, and compared them to ONGAEIR [2]. Its stated purpose was to “provide recommended ratios of modeled total emissions to corresponding reported emissions” [2].
COBE differs from 1.164 partly because it measured differently, its models disagree, and its baseline moved to 2024 ONGAEIR. The 2025 multiplier rested on Carbon Mapper aerial data gathered over an 18-day campaign [10]. 92.8 percent of what it detected sat above 50 kg/h [10]. The paper notes that aerial surveys “face challenges in fully capturing CH4 emissions due to their temporal limitations, variability in measurements, and detection thresholds” [10].
COBE’s vendors reported detection limits of 25 kg/h or lower; that is a different measure from a 90 percent detection probability [2]. It used three aerial vendors rather than one [2]. GHGSat’s two sensor generations reported detection limits of 10 and 5 kg/h, and Insight M’s two sensors 25 and 10 kg/h [2].
Bridger’s Gas Mapping LiDAR had the lowest detection limit of the three, reaching 90 percent probability of detection around 1.27 kg/h [2]. The Colorado School of Mines model used continuous-monitoring data and two published estimates to account for the emissions below those limits [2].
It also covered far more ground [2]. Of Colorado’s 11,681 operating upstream facilities, 9,411 were modelled [2].
A campaign that resolves smaller emissions finds more of what a bottom-up inventory omits, though aerial snapshots still miss transient events. The 2025 paper anticipated the gap, noting that “annual inventories submitted by operators likely don’t include emissions from failure events” [10].
Two teams modelled the same measurements and did not agree [2]. METEC used a mechanistic model and Colorado School of Mines used a statistical one [2]. CDPHE set the 2026 state default factors by averaging the two models’ results [8].
| Model | Statewide emissions estimate | Ratio to reported |
|---|---|---|
| Mechanistic Air Emissions Simulator (MAES), METEC | 38,936 mt/y | 1.47 |
| Statistical model, Colorado School of Mines, same facility subset | 87,210 to 134,352 mt/y | 3.30 to 5.09 |
| Statistical model, all ONGAEIR facilities | about 109,400 to 167,800 mt/y | 3.81 to 5.85 |
Ratios of modelled total emissions to reported emissions, from the 2024 ONGAEIR dataset. [2]
The MAES ratio of 1.47 compares like with like [2]. The report adds ONGAEIR’s 2,339 mt/y of maintenance to MAES: 38,936 against an ONGAEIR total of 26,415 [2]. Without maintenance on either side, the MAES total of 36,597 mt/y is 52 percent above the adjusted 24,076 [2]. CDPHE dropped the top, continuous-monitoring variant of the statistical model for lack of representativeness when it set the 2026 factors [8].
The two COBE models applied to the same underlying measurements. TetraSoft analysis of the COBE Updated Final Report, November 2025, and CDPHE’s 2026 factors.
The report is explicit about what those ratios are not. It states the ratios “are specific to the ONGAEIR data and should not be interpreted as methane ratios related to total production in Colorado” [2].
Nineteen percent of facilities could not be modelled in MAES, because their ONGAEIR entries were missing key information [2]. An incomplete filing can therefore keep a facility out of a measurement-informed model.
If your 2026 default factor and your own measurements would put you on opposite sides of the target, run the arithmetic on the operator-specific route.
The Way Out Is a Measurement-Informed Inventory
Section VIII.F.3.b is the alternative to accepting whatever multiplier the state publishes [1]. It lets an operator use an operator-specific program built on a measurement strategy [1]. For calendar years 2025 and 2026 that strategy must be one the Division developed [1]. From calendar year 2027 operators may also use their own strategy, submitted for Division approval by March 31 of the year before use [1].
On the 2026 numbers, the default factor an operator must apply is 2.2 to 2.7, depending on region [8]. That factor can be the difference between clearing an intensity target and missing it.
The TetraSoft MAES Platform, our subscription platform for emissions modelling, runs the Mechanistic Air Emissions Simulator [11]. METEC built one of COBE’s two inventories with it [2]. MAES builds a facility from its equipment, its operating states and its gas composition [2]. It then adds the measured emissions the reported inventory does not already contain, often from abnormal conditions or equipment failures [2].
The distinction that matters for an individual operator is how much detail the model has to work with. A statewide study models thousands of sites from what the inventory happens to record, and fills the gaps with assumptions where facility detail is missing [2]. An operator running the same model on their own sites supplies equipment counts, operating conditions and gas compositions directly.
What that produces is an expected emission range built from your sites rather than from the state’s average. Whether it lands above or below the default is an empirical question about your operations.
The model was developed at CSU and UT Austin, and TetraSoft uses it through a partnership with CSU [11].
An operator-specific program also needs an approved measurement strategy, a certified third-party audit and a September 30 notice, all separate from the model [1].
What Changed in Regulation 7 This Year
Three permanent rule amendments to Regulation 7 took effect in the twelve months to September 2026, plus a correction [3]. Permanent rules took effect on January 14, 2026, April 14, 2026 and July 15, 2026, with a correction also effective July 15, 2026 [3]. A further revision, adopted September 18, 2026, takes effect November 14, 2026 [4]. Here is what each one did.
January adds a leak duty, April adds methane duties and delays small-operator targets, and July changes Section V reporting. Section I.A.5., effective January 14, 2026, extended the leak detection program to transmission and storage segment facilities in northern Weld County [1]. It covers those that emitted, or had the potential to emit, 50 tons per year or more of VOC as of July 24, 2024 [1].
The April 14 version aligned transmission and storage duties with EPA’s methane guidelines (EG OOOOc) and delayed targets for operators below 45 kBOE to 2030 [1]. Effective July 15, 2026, Section V reporting became an Emissions Reporting Notice, and the Division’s annual summary report duty was repealed [1].
A second phase, COBE-2, will reconcile the two models and develop recommended default factors for 2027 [2]. It is scheduled to run into early 2027, and its results were not yet published as of November 2026 [12]. Lowering your own factor through an approved program is covered in How to Get a Colorado Operator-Specific Verification Factor.
Frequently Asked Questions
Is Colorado Regulation 7 Part D the same as Part B?
Part D is the old numbering [3]. The version effective June 14, 2023 restructured it to Parts A, B and C [3].
Does Colorado Regulation 7 apply outside the Denver ozone area?
Yes, for Part B Sections II through VIII, apart from Section VI.E [1]. Part B Section I is the geographically limited one, along with Section VI.E’s May to September limits on drilling, pre-production and production operations [1]. It reaches the 8-Hour Ozone Control Area and northern Weld County [1].
What is a measurement-informed inventory?
Regulation 7 defines it as the ONGAEIR emissions inventory informed by direct measurement and, optionally, parametric measurement [1]. In COBE’s MAES approach that meant starting from the reported inventory and adding measured emissions it did not already contain [2].
Why did the two COBE models disagree so much?
The report has not yet settled why, but it names emissions below 5 kg/h as a key discrepancy [2]. Aerial surveys do not fully capture emissions below their detection limits, and the two models estimate that range in different ways [2]. The mechanistic model builds each facility from its reported equipment, which anchors its total to the inventory [2]. The statistical model extrapolates from the measured distribution across facilities [2].
Is Colorado Regulation 7 federally enforceable?
Only in part [1]. Part A provides that Sections II through VIII, and any other section marked State Only, are not federally enforceable unless otherwise identified [1]. The distinction decides whether EPA, and citizens under Clean Air Act section 304, can also enforce a requirement, not whether it binds you.
Interested in building a Measurement-Informed Inventory for your operations? Contact us to learn about our MAES-based estimation services.
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.
References
- Colorado AQCC Regulation Number 7, 5 CCR 1001-9, Control of Emissions from Oil and Gas Emissions Operations, version effective July 15, 2026. Colorado Secretary of State, Code of Colorado Regulations. https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=12621&fileName=5%20CCR%201001-9
- Brown et al., 2025, Colorado Ongoing Basin Emissions Updated Final Report, Energy Institute, METEC, Colorado State University, and Colorado School of Mines, November 20, 2025. Authors: Brown, J. A.; Moy, M.; Santos, A.; Rimelman, E.; Mollel, W.; Khaliukova, O.; Okenberg, C.; Daniels, W. S.; Hammerling, D. M.; Zimmerle, D.; Hodshire, A. L. Colorado State University repository: https://hdl.handle.net/10217/242813
- Colorado Secretary of State, rule history for 5 CCR 1001-9, Air Quality Control Commission. https://www.coloradosos.gov/CCR/DisplayRule.do?action=ruleinfo&ruleId=2341&deptID=16&agencyID=7&deptName=Department+of+Public+Health+and+Environment&agencyName=Air+Quality+Control+Commission&seriesNum=5+CCR+1001-9
- CDPHE, Air Quality Control Commission regulations. Lists Regulation Number 7, 5 CCR 1001-9, as adopted 09/18/26, effective 11/14/26. https://cdphe.colorado.gov/aqcc-regulations
- US EPA, 40 CFR 52.320, Identification of plan (Colorado), eCFR, https://www.ecfr.gov/current/title-40/chapter-I/subchapter-C/part-52/subpart-G/section-52.320. Code of Federal Regulations, eCFR text as of October 30, 2026.
- US EPA, NAAQS Table, criteria air pollutants. https://www.epa.gov/criteria-air-pollutants/naaqs-table
- ECMC well data, Wells shapefile dated November 3, 2026, https://ecmc.colorado.gov/data-maps-reports/downloadable-data-documents (Well Spots (APIs) shapefile, updated daily). 124,467 well records statewide, all statuses including active and expired permits; 54,522 in the Section I area (Larimer clipped at the Part A II.A.1.a line); 45,882 in Weld County; 12,116 of 36,067 producing wells in the Section I area.
- CDPHE, Oil and Gas Greenhouse Gas Intensity Program. https://cdphe.colorado.gov/oil-and-gas-greenhouse-gas-intensity-program
- Computed from the 2025 state default verification factor of 1.164 applied to a 500 metric ton reported figure. No external source.
- Santos et al., 2025, ACS ES&T Air, 2, 1598-1611, DOI 10.1021/acsestair.5c00089. Using Measurement-Informed Inventory to Assess Emissions in the Denver-Julesburg Basin. https://doi.org/10.1021/acsestair.5c00089
- TetraSoft, MAES Platform. https://www.tetrasoftco.com/maes-platform/maes-landing.html
- METEC, Colorado Ongoing Basin Emissions Study 2 (COBE-2), Colorado State University. https://metec.colostate.edu/colorado-ongoing-basin-emissions-study-cobe-2/
Applicability screener
Which parts of Regulation 7 reach this facility?
Geography decides first. Section I is an ozone-area rule; Sections II to VIII are statewide.
Highest emitting single tank where tanks are present, not the facility total.
Part B Section I applies, and so do Sections II to VIII
Leak inspections: At least annually
Statewide regardless of location
- IIStatewide controls for oil and gas operations
- IIIPneumatic controllers and pneumatic pumps
- IVNatural gas transmission and storage segment
- VOil and natural gas operations emissions inventory
- VIPre-production, early-production and production operations
- VIIMidstream segment fuel combustion equipment
- VIIIGreenhouse gas intensity program, upstream segment
Screens the applicability tests as worded in 5 CCR 1001-9, version effective July 15, 2026. It does not know where your facility is, does not compute uncontrolled VOC emissions, and does not resolve the Larimer and Weld boundary, which the regulation draws by latitude rather than by county line. LDAR tiers from Part B, Section I.L.: at least annually from 1 to 6 tons per year, at least semi-annually above 6.
Comments
0Share your thoughts. All comments are moderated before appearing.
No comments yet. Be the first to share your thoughts!