EPA Proposes Significant Revisions to Oil and Gas Methane and VOC Regulations

Key Takeaways

• What Happened: On October 29, 2026, the U.S. Environmental Protection Agency (EPA) opened comment on a proposal to significantly revise its New Source Performance Standards (NSPS) for emissions of methane and volatile organic compounds (VOC) from new, modified, and reconstructed oil and natural gas sources (Subpart OOOOb), as well as its emission guidelines for methane emissions from existing oil and natural gas sources (Subpart OOOOc). The proposal would rescind the “Super Emitter Program” (including related provisions in earlier NSPS subparts), and revise requirements for certain well sites, covers and closed vent systems, associated gas, and control devices. It also addresses process controllers, pumps, liquids unloading events, fugitive emissions, storage vessels, equipment leaks at gas plants, and other technical and operational requirements.
• Who’s Impacted: Oil and natural gas producers, and owners and operators of covered well sites, gathering and boosting stations, gas processing plants, compressor stations, and transmission and storage facilities. The proposal is particularly relevant to operators of low-producing wells, facilities handling associated gas, and facilities using natural-gas-driven controllers and pumps.
• What to Do: Operators should evaluate the proposed changes against existing compliance obligations, applicable state requirements, and permit conditions. Stakeholders should consider submitting comments by December 16, 2026. EPA will hold a virtual public hearing on November 16, 2026.  

Background: EPA’s Continued Reconsideration of Oil and Gas Requirements under the Clean Air Act

EPA’s October 29 proposal would revise federal requirements for methane and volatile organic compound (VOC) emissions from the oil and natural gas sector. The proposal addresses two distinct regulatory programs under Clean Air Act (CAA) Section 111. The New Source Performance Standards (NSPS) in 40 C.F.R. Part 60, Subpart OOOOb directly regulate methane and VOC emissions from covered new, modified, and reconstructed sources. The Emission Guidelines (EG) in Subpart OOOOc, by contrast, establish methane emission guidelines and presumptive standards for states developing plans to regulate existing sources under CAA Section 111(d).

The Biden administration finalized OOOOb and OOOOc in March 2024. Together, they established requirements for covered facilities and equipment across oil and natural gas production, gathering and boosting, processing, transmission, and storage operations. The rule required operators to control emissions from various sources and established presumptive methane standards for states to incorporate into plans for existing sources.

The Trump administration began reconsidering these requirements in 2025. On March 12, 2025, Administrator Lee Zeldin announced plans to reconsider the oil and gas regulations as part of a broader deregulatory initiative, describing them as “regulations throttling the oil and gas industry.” EPA then extended several compliance deadlines through an interim final rule in July 2025 and a final rule in December 2025. Those extensions affected control devices, equipment leaks, storage vessels, process controllers, covers and closed vent systems, and the Super Emitter Program. In April 2026, EPA finalized additional revisions that allow operators greater flexibility to temporarily flare associated gas and ease requirements for monitoring and testing the net heating value of gas sent to combustion control devices. Separately, in April 30, 2026 guidance, EPA confirmed that operators may flare associated gas for up to 30 days per incident when downstream pipeline or gathering-system interruptions beyond their control prevent gas from reaching market.

The October proposal represents the most consequential step in EPA’s reconsideration to date. Moving beyond deadline extensions and technical amendments, EPA proposes to revisit the substance of several 2024 requirements. In a press release, EPA Administrator Lee Zeldin described the proposal as part of President Trump’s “promise[] to end the war on oil and natural gas.” EPA projects the proposed revisions would produce approximately $45 billion in economic benefits over 2027–2050 and increase U.S. production by approximately 210 million barrels of oil and 1.41 trillion cubic feet of natural gas.

EPA’s Proposed Changes

1. Eliminating the Super Emitter Program

EPA proposes rescinding the Super Emitter Program, designed to allow EPA-certified third parties to use satellite imagery, aerial surveys, and other remote sensing technologies to identify large methane releases from oil and natural gas facilities. Under the 2024 rule, certified third parties may report emissions of at least 100 kilograms per hour to EPA. After reviewing a report, EPA notifies the potentially responsible operator, who must investigate the alleged release, report its findings, and take certain corrective actions. In 2025, EPA delayed implementation of the program until January 22, 2027.

EPA now proposes to remove the program from NSPS Subpart OOOOb (and its predecessors NSPS Subparts OOOO and OOOOa), as well as EG Subpart OOOOc. EPA questions whether the program would effectively identify actionable emission events, citing “insufficient evidence of the nature and duration of super-emitter events.” EPA also argues that existing monitoring and repair requirements address significant releases and questions whether CAA Sections 111 and 114 authorize the program’s “novel” third-party notification and investigation framework. Rescission would eliminate the Super Emitter Program certification and procedures, but would leave in place the applicable leak detection, repair, and reporting requirements. Notwithstanding the proposed federal repeal, some states operate or are developing similar programs.

2. New Subcategories for Marginal or Conventional Well Sites, with Less Stringent Requirements

EPA proposes two alternative approaches to easing emissions requirements for certain oil and natural gas well sites. Both would establish new regulatory subcategories under NSPS OOOOb and EG OOOOc, allowing qualifying sites to comply with less stringent requirements for fugitive emissions monitoring and certain natural gas-driven equipment.

• Under the first alternative, EPA would establish a separate, less stringent subcategory for “marginal well sites” based on production volume. To qualify, each well at the site would have to meet the proposed marginal-well criteria, and total site production could not exceed 15 barrels of oil equivalent per day, averaged over the preceding 12 months.
• Under the second alternative, EPA would establish a separate, less stringent subcategory “conventional well sites,” defined as sites containing only conventional oil or natural gas wells. Conventional wells generally produce from relatively permeable rock formations, whereas “unconventional” wells produce from shale or other low-permeability formations and typically require hydraulic fracturing. Unlike the marginal well approach, eligibility under this approach would not depend on production volume. However, among other things, EPA reasons that this approach would reduce administrative burdens and ensure consistent treatment of a well-site throughout its lifespan, even as production volume changes.

Under either alternative, qualifying sites would generally face less stringent requirements, including quarterly audio, visual, and olfactory (AVO) inspections instead of more intensive instrument-based fugitive-emissions monitoring, along with greater flexibility for certain process controllers and pumps.

EPA also proposes new criteria for determining when modifications to existing marginal or conventional well sites trigger NSPS OOOOb applicability. These include certain activities intended to increase production, changes in well operations, and the addition of specified natural-gas-driven process controllers, pumps, or storage vessels. Under the proposal, a qualifying modification or reconstruction could bring the entire well site under OOOOb, not just the modified equipment.

3. Relaxed Requirements for Covers and Closed Vent Systems

EPA proposes dividing the current requirements for covers and closed vent systems into distinct design and operational standards, and changing a position in the 2024 rule preamble that “any identified emissions would be a deviation of this emissions limitation.”

The 2024 rule requires covered equipment to be designed and operated with no identifiable emissions (NIE) and establishes inspection, monitoring, and leak repair requirements to ensure compliance. EPA previously delayed the compliance deadline for these NIE inspection requirements to January 22, 2027. EPA’s new proposal would remove the separate requirement that equipment be designed to achieve NIE, but retain requirements to capture and route emissions to a control device or process and to operate without identifiable emissions. EPA also proposes to allow operators to address detected emissions or defects through established repair procedures. Unlike the 2024 rule, under which any detected emissions constitute an immediate deviation, the proposed rule would generally give operators 24 hours to complete repairs without triggering a design deviation. Operators could also maintain operational compliance by attempting an initial repair within five days and completing repairs within 30 days, subject to applicable exceptions and delay-of-repair provisions.

The proposal would also require operators to investigate recurring problems involving the same cover or closed vent system after three identified emissions events or defects within a rolling year and implement corrective measures.

4. Relaxed Requirements for Flaring of Associated Gas

EPA proposes to significantly revise the 2024 rule’s limitations on flaring of associated gas produced alongside oil. The 2024 rule generally requires covered operators to capture and route associated gas to a flow or sales line, recover it for another useful purpose, or reinject it, while restricting routine flaring, subject to specified exceptions. EPA previously finalized technical amendments and issued guidance dated April 30, 2026, recognizing limited circumstances in which temporary flaring may continue after the initial May 7, 2026 phaseout deadline.

Under the current proposal, EPA would revise its determination of the best system of emission reduction (BSER) to allow operators to routinely route associated gas through a closed vent system to a flare or other control device achieving at least 95% reduction in methane and VOC emissions. Operators would no longer be required to prioritize recovering or selling associated gas over routing it to a flare or other qualifying control device. EPA reasons that the 2024 rule’s preference for capturing and selling associated gas depends on third-party gathering and pipeline infrastructure that may be unavailable or outside operators’ control, whereas flaring provides an established means of reducing emissions without relying on that infrastructure.

EPA also seeks comment on an alternative approach that would retain the 2024 rule’s BSER determination while making narrower changes to address implementation challenges. If finalized as principally proposed, the rule would substantially expand operational flexibility for associated-gas flaring at the federal level.

5. Increased Flexibility for Control Devices

EPA proposes technical revisions to requirements governing emissions control devices, including deviations in flame monitoring data, control-device alerts, and visible-emissions testing. The 2024 rule establishes performance, net heating value (NHV) monitoring, compliance testing, and recordkeeping requirements intended to verify effective emissions control. EPA’s April 2026 amendments had already relaxed certain NHV monitoring and testing requirements for flares and enclosed combustion devices.

Under the current proposal, EPA would provide operators greater flexibility to demonstrate compliance during gaps in flame monitoring data. Operators could use supplemental “documented information,” such as temperature readings before and after a brief gap in monitoring data, to demonstrate that a pilot or combustion flame remained lit during the gap, rather than treating every gap as a deviation. EPA would also allow flame failure alerts to be transmitted to centralized control rooms rather than only to the nearest control room, and would provide an additional 24 operating hours after the end of each calendar month to complete required Method 22 visible emissions observations.

6. Other Equipment and Monitoring Revisions

EPA also proposes several other equipment-specific changes, including additional flexibility for process controllers, pneumatic pumps, and liquids unloading operations. The proposal would also revise certain fugitive emissions monitoring requirements, storage-vessel applicability criteria, and equipment leak monitoring provisions. These and other proposed changes could provide additional compliance flexibility for affected oil and natural gas operators.

State Regulation Continues Despite Federal Rollback Efforts

EPA’s reconsideration comes amid continued state activity to regulate methane and VOC emissions. Colorado, New Mexico, and California illustrate how state requirements may persist or become more stringent even as EPA proposes adjustments to the federal requirements in Subparts OOOOb and OOOOc.

Colorado

Colorado has continued strengthening its oil and gas regulations, including a series of rulemakings that go beyond the federal implementing requirements in EPA’s 2024 OOOOb/c.

In December 2024, Colorado adopted regulations targeting greenhouse gas emissions from midstream fuel combustion equipment (MFCE), including engines, turbines, and heaters used in natural gas gathering, compression, and processing operations. Under Regulation 7, Part B, Section VII, midstream operators must meet company-specific emissions caps by December 31, 2030, to achieve a sector-wide emissions cap of approximately 3.93 million metric tons of carbon dioxide equivalent annually, with compliance options including onsite emissions reductions and, subject to restrictions, greenhouse gas emission credits.

In February 2025, the Colorado Air Quality Control Commission (Commission) adopted requirements to phase out certain natural gas-emitting pneumatic devices. In February 2026, it strengthened instrument-based leak detection and repair requirements, including for low-producing, wellhead-only facilities. In September 2026, the Commission adopted additional standards for covers, closed vent systems, and enclosed combustion devices, including provisions extending beyond the federal baseline.

Colorado officials have emphasized that federal deregulation does not limit the Rocky Mountain State’s authority to maintain its own methane requirements. As Stefanie Shoup, deputy director of Colorado’s Air Pollution Control Division, stated after EPA’s October announcement, “We have broad authority [under Colorado law] to develop and implement state-only rules regardless of what is happening at the federal level.”

New Mexico

New Mexico also maintains extensive methane regulations, including its Methane Waste Rule, which restricts routine venting and flaring and requires operators to capture 98 percent of natural gas by December 31, 2026. New Mexico’s separate ozone precursor rule imposes VOC emissions control and monitoring requirements on new and existing oil and gas operations in designated counties.

In July 2026, the New Mexico Environment Department proposed an additional methane abatement rule, 20.2.51 NMAC, establishing a state-level “super-emitter event” notification and investigation program. The proposed rule would also mandate zero methane emissions beginning January 1, 2031, from covered process controllers at well sites, tank batteries, gathering and boosting stations, natural gas processing plants, and transmission compressor stations. The state’s Environmental Improvement Board has scheduled a hearing on 20.2.51 NMAC for December 1–8, 2026.

Governor Michelle Lujan Grisham has made clear that New Mexico intends to continue regulating methane despite EPA’s continued deregulatory effort at the federal level. In response to EPA’s October announcement, she declared that the state’s “methane rules will remain firmly in place” and that New Mexico plans to strengthen them.

California

California maintains an independent methane regulatory program for new and existing oil and gas facilities under the California Air Resources Board’s (CARB) Oil and Gas Methane Regulation (17 CCR §§ 95665–95677). Adopted in 2017 and amended in 2024, the regulation establishes leak detection and repair requirements, emissions controls for storage tanks, compressors, and other equipment, and annual reporting obligations. The 2024 amendments also added requirements—similar to the Super Emitter Program—to investigate and address methane emissions identified through remote monitoring. Under 17 CCR § 95669.1, operators notified by CARB of methane plumes detected through approved remote-monitoring technology generally must inspect their facilities within five calendar days and comply with applicable repair and reporting requirements. These requirements provide a state-level counterpart to the federal Super Emitter Program that EPA now proposes to rescind, although the programs differ in scope and procedures. California’s independent requirements would remain enforceable notwithstanding any relaxation of federal standards or emission guidelines.

California has likewise emphasized its continued methane-monitoring efforts. Announcing the launch of the Golden State’s second methane-detecting satellite in October 2026, Governor Gavin Newsom stated, “California is doubling down on methane-detecting technology,” adding, “We’re finding methane leaks and getting them fixed.”

Implications and Next Steps for Operators

EPA’s proposal could substantially reduce federal compliance obligations for certain oil and natural gas operations, but it would not eliminate the underlying regulatory framework. New, modified, and reconstructed sources would remain subject to many standards and requirements under Subpart OOOOb, while Subpart OOOOc would continue to establish emission guidelines for existing sources and provide a framework for state plans under CAA Section 111(d). The extent of any compliance relief will depend on the final federal rule and applicable state and local requirements. In particular, operators in states with independent methane and VOC regulations may remain subject to requirements similar to those EPA proposes to relax or eliminate federally.

Operators should take the following steps:

• Consider submitting comments on the proposal. EPA is accepting comments through December 16, 2026. Operators should evaluate whether the proposed changes adequately address their operational circumstances and whether they possess safety, technical, operational, or economic information that could inform EPA’s final decisions.
• Evaluate existing compliance obligations. The October proposal does not change currently applicable requirements. Operators should review their federal compliance deadlines, state regulations, and permit conditions before modifying planned compliance measures or investments.
• Assess state-specific requirements. Operators with facilities in multiple states should identify where state methane and VOC requirements may differ from the proposed federal changes, particularly for fugitive emissions monitoring, process controllers, flaring of associated gas, and “super emitter”-style detection and response programs.

Beveridge & Diamond’s Air and Oil and Gas practices advise companies, trade associations, and other stakeholders on rulemakings, permitting, compliance, enforcement, and litigation under the Clean Air Act and state laws. Our lawyers help clients navigate evolving emissions requirements, evaluate regulatory risks, and engage with agencies on proposed regulatory changes. For more information on these developments, please contact the authors.