Colorado Air Quality Regulation Number 7 (Reg 7) governs the control of ozone precursors and hydrocarbons from oil and gas operations throughout the state. Administered by the Colorado Department of Public Health and Environment (CDPHE) Air Pollution Control Division and adopted by the Air Quality Control Commission (AQCC), Reg 7 Part D contains some of the most stringent oil and gas air emission requirements in the nation. Colorado was the first state to establish methane emissions targets for oil and gas (2014), the first to adopt a GHG emissions intensity verification program (2023), and the first to implement a midstream GHG reduction rule (2024). The regulation covers leak detection and repair (LDAR), storage tank emissions management (STEM), pneumatic controllers, compressor stations, engines and combustion equipment, glycol dehydrators, well production facility design, and annual emissions inventory reporting. In February 2025, the AQCC approved additional measures to phase out natural gas-driven pneumatic devices statewide and align with federal NSPS OOOOb requirements. This checklist covers the key compliance elements of Reg 7 Part D for upstream and midstream oil and gas operators in Colorado.
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Colorado Regulation 7, Part D — Oil and Gas Operations
Part D establishes emission control requirements for oil and gas well production facilities, compressor stations, natural gas processing plants, and transmission facilities. Key sections include: Section II (equipment standards for storage tanks, pneumatics, compressors, dehydrators, LDAR), Section III (air quality monitoring), Section V (annual emissions inventory reporting), and Section VIII (GHG intensity verification program for upstream operations).
Colorado Regulation 7, Part B — Midstream Operations
Part B, Sections VII and VIII (previously in Regulation 22) address GHG emissions from midstream fuel combustion equipment and the upstream segment GHG intensity verification program. The December 2024 midstream rule requires GHG reduction planning and a 2030 sector-wide emissions limit for compressor stations and processing plants.
Colorado SB 19-181 and the Greenhouse Gas Pollution Reduction Roadmap
Senate Bill 19-181 reformed oil and gas regulation in Colorado to prioritize public health and the environment. The Colorado GHG Pollution Reduction Roadmap establishes targets of 26% reduction by 2025, 50% by 2030, and 90% by 2050 from 2005 levels. The oil and gas sector must reduce emissions 36% by 2025 and 60% by 2030 relative to 2005 levels.
Leak Detection and Repair (LDAR)
| Audit Item | Expected Finding / What to Evaluate |
|---|---|
| LDAR program and inspection frequency | LDAR program covers all applicable components at well production facilities, compressor stations, and processing plants. Inspections are conducted using OGI (IR camera) or Method 21 at frequencies meeting or exceeding Reg 7 requirements: monthly for facilities with emissions ≥12 tpy VOC in the nonattainment area, quarterly for most other facilities, and at minimum frequencies for lower-emission facilities. AVO (audio, visual, olfactory) inspections supplement instrument-based surveys. |
| Leak repair timeliness | Identified leaks are repaired within 15 days of discovery per Reg 7 Part D, Section II.E. First attempt at repair is made within 5 days. If repair cannot be completed within 15 days, a delay of repair is documented with justification, estimated repair date, and interim emission reduction measures. Delay of repair records are maintained. |
| LDAR recordkeeping | Records maintained for each LDAR inspection include: date, time, inspector identity, instrument used and calibration status, components surveyed, leaks identified (location, component type, estimated emission rate), repair dates, and verification that repair was effective. Records are retained for a minimum of five years and are available for CDPHE inspection. |
| Alternative monitoring technologies | If using alternative monitoring technologies (continuous monitoring systems, aerial surveys, drone-mounted OGI), the operator has obtained CDPHE approval through an alternative monitoring plan per Reg 7 requirements. Approval documentation is on file. Technology meets performance criteria specified in the approval. |
Storage Tank Emissions Management
| Audit Item | Expected Finding / What to Evaluate |
|---|---|
| STEM plan | Storage Tank Emissions Management (STEM) plan per Reg 7 Part D, Section II.C exists for each applicable tank battery. STEM plan identifies all storage vessels, estimated uncontrolled emissions, control equipment, and compliance pathway (control device, vapor recovery, or tank design). STEM plan is current and reflects actual operations. |
| Storage tank control requirements | Storage tanks with uncontrolled VOC emissions ≥2 tpy (statewide threshold) route emissions to a control device achieving ≥95% destruction/removal efficiency or to a vapor recovery unit. Tanks in the nonattainment area meeting lower thresholds also comply. Thief hatches and other openings are properly sealed. |
| Auto-gauging and loadout controls | Where required, auto-gauging systems are installed to minimize manual tank gauging emissions. Loadout operations use vapor-tight connections and route displaced vapors to a control device or VRU. Truck loading operations comply with Reg 7 loading loss requirements. |
| Tank inspection and maintenance | Storage tanks, seals, hatches, pressure/vacuum relief devices, and closed vent systems are inspected at required frequencies. Deficiencies are documented and repaired promptly. Annual or more frequent inspections of control device connections and tank integrity are conducted. |
Pneumatic Controllers and Compressors
| Audit Item | Expected Finding / What to Evaluate |
|---|---|
| Pneumatic controller requirements | All pneumatic controllers at upstream facilities comply with Reg 7 requirements: controllers placed in service after February 1, 2009 are low-bleed (≤6 scfh); at processing plants, controllers installed after January 1, 2018 are zero-bleed. Per the February 2025 AQCC rule, all natural gas-driven pneumatic controllers are being phased out statewide on an accelerated timeline (more stringent than the federal March 2029 deadline). Phase-out schedule compliance is tracked. |
| Pneumatic controller inventory and reporting | Complete inventory of all pneumatic controllers is maintained with: location, type (continuous bleed high/low, intermittent, zero-emission), manufacturer, bleed rate, and date installed. Pneumatic controller reporting forms are submitted to CDPHE as required. Changes to inventory are updated promptly. |
| Compressor emission controls | Wet seal centrifugal compressors reduce emissions by ≥95% (Reg 7 Part D, Section II.B). Reciprocating compressor rod packing is replaced every 26,000 operating hours or 36 months, whichever comes first. Compressor station fugitive emissions are addressed through the LDAR program. |
| Engine and turbine emissions | Stationary engines and turbines at oil and gas facilities meet Reg 7 emission limits for NOx, CO, and VOC. Engines are tested or monitored at required intervals. Engine emission records including manufacturer data, operating hours, and test results are maintained. |
GHG Intensity and Emissions Reporting
| Audit Item | Expected Finding / What to Evaluate |
|---|---|
| GHG intensity verification program | If operating in the upstream segment, facility participates in the GHG intensity verification program per Reg 7 Part B, Section VIII. Measurement-informed methane emissions inventory is prepared. GHG intensity is calculated per 1,000 barrels of oil equivalent (BOE). Intensity meets the declining annual limit (starting at 11 tons CO₂e/1,000 BOE in 2025 for large operators, decreasing through 2030). |
| Annual emissions inventory report (ONGAEIR) | Oil and Natural Gas Annual Emissions Inventory Report is submitted to CDPHE by June 30 annually for the prior calendar year. Report includes emissions of VOC, NOx, CO, methane, and other pollutants from all sources. Report uses required methodology and emission factors. State default intensity verification factor (1.164 for 2025) is applied unless an operator-specific program is approved. |
| Midstream GHG reduction planning | If operating midstream facilities (compressor stations, processing plants), GHG reduction plan is developed per the December 2024 midstream rule (Reg 7 Part B, Section VII). Plan addresses emissions from fuel combustion equipment (engines, turbines, heaters). Steps to reduce emissions commenced by February 14, 2025. Company is on track for the 2030 sector-wide emissions limit. |
| Emission control device (ECD) monitoring | Emission control devices (flares, enclosed combustors, VRUs) are monitored per Reg 7 ECD requirements. Continuous pilot monitoring or equivalent is in place. ECD performance tests are conducted as required. Uptime records demonstrate the ECD is operating at required levels. Any deviations are documented and reported. |
Air Monitoring, Permits, and Recordkeeping
| Audit Item | Expected Finding / What to Evaluate |
|---|---|
| Pre-production and facility air monitoring | Where required by Reg 7 Part D, Section III (effective July 2024 with 2025 revisions), air quality monitoring is conducted at or near well production facilities during pre-production and early production. Monitoring plan is approved by CDPHE. Monitoring data is submitted on monthly reporting forms. Data quality meets CDPHE guidance. |
| APEN and permit compliance | Air Pollutant Emission Notices (APENs) are current for all applicable sources. Permit conditions are documented and tracked. Any changes to emissions that trigger permit modifications or new APENs are addressed within required timeframes. Permit conditions align with actual operations. |
| Disproportionately impacted community (DIC) requirements | Facilities located near disproportionately impacted communities (as mapped by CDPHE’s November 2024 DIC map) comply with any additional requirements including enhanced monitoring, notification, or emission controls. DIC status of facility locations is assessed using the current CDPHE map. |
| Record retention and availability | All Reg 7 compliance records are retained for a minimum of five years including: LDAR inspection records, STEM plans, emissions calculations, ECD performance data, monitoring data, training records, and annual reports. Records are organized and available for CDPHE inspection upon request. |
Corrective Actions
Common Issues and Responses
- LDAR inspections behind schedule: Conduct overdue inspections immediately. Implement automated scheduling with calendar reminders. Consider contracting a third-party LDAR provider if internal resources are insufficient to maintain required frequencies.
- Storage tanks lacking required controls: Evaluate uncontrolled emissions from each tank battery. Install vapor recovery or route emissions to a control device for tanks exceeding the 2 tpy VOC threshold. Update the STEM plan. Prioritize tanks in the nonattainment area.
- Non-compliant pneumatic controllers: Inventory all pneumatic controllers and identify high-bleed and non-compliant devices. Develop a replacement schedule aligned with the AQCC phase-out timeline. Replace with zero-emission (instrument air or electric) controllers where feasible. Report controller inventory changes to CDPHE.
- GHG intensity exceeding target: Identify the highest-emitting sources and implement cost-effective reduction measures. Review measurement-informed inventory for data quality. Evaluate whether an operator-specific verification program would be beneficial. Document all reduction actions taken.
- Late or incomplete annual emissions report: Submit the report immediately to CDPHE. Implement a data collection system that gathers emissions information throughout the year. Assign report preparation responsibilities with a timeline starting in January for the June 30 deadline.
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